Journal IATMI is a collection of scientific publications owned by Indonesian Association of Petroleum Engineers (IATMI) consisting of Symposium Proceedings, JTMGB magazine, as well as other journal publications, which can be used as a reference for literatures, but not limited to, the oil and gas industry.
Ikatan Ahli Teknik Perminyakan Indonesia
Precise Determination of Probable Leak Path and Associated Source Noise with The Novel Technique of “Beamforming” Using Multiple Hydrophone Arrays; A Case Study from Sanggar-06 Well Indonesia
The Beamforming technique was proven to leverage noise detection with multiple - hydrophone, it was designed to process the multiple waveforms from hydrophone in the frequency domain and modeled the delay time of leak signal arrivals between the hydrophones in order to locate the accurate leak position and flow path. The purpose of this paper to show the combination of these techniques that are -provide critical information for further plans to restore well barrier condition. Sanggar-06 well has a mechanical problem on the 5-1/2” Tubing connection after the completion program in 2004, it was detected some joints was not tightened properly as shown by Caliper Survey. Based on daily monitoring in early 2011, the tubing pressure and A-Annulus pressure at the same pressure level and indicated continuous communication both in shut-in and flowing conditions. The first noise log survey was run in May 2011 and detected 2 leak points, later the leak path was isolated with Tubing Patch by April 2012 and solved the problem. In March 2017 the Sanggar-06 exhibited the same problem of communication between Tubing and AAnnulu.s, this was then followed up with 2nd run of the noise log.The result from this noise log run did not show a clear indication of where the leak position was located and indicated a 7-point potential leak position on the production string. Before the decision to have a retubing program to recover the tubing integrity, the 3 noise log was run by adding 3 hydrophones (a total 6 hydrophones) and implementing a beamforming technique to locate the leak point. The re-run was paid off with the result by that confirming a leak point at the from packer assembly. The benefit of this work has resulted in changes of the original tubing integrity recovery plan that use work over rig to rigless activity; which have impact massive or cost saving terms of restoring the well barriers objective in the execution of this operation.
A Novel Approach for New Well Placements Using Dynamic Data and Flowing Material Balance
W Field is a carbonate reservoir which produced on a thin oil rim with a gas cap. The W field is one of the newest fields in UP area and producing from 4 wells within 1-year production period. The adjacent field with similar features with W field shows challenging in field development with low recovery factors, especially in selecting new well proposed locations. Furthermore, dynamic simulation couldn’t be used, since history matching always become problems in this field where fracture and vugs have big contributions to well performances. Even generating bubble maps using decline curve analysis will give high uncertainty since well recovery factor is unknown. Therefore, reliable methods to determine each well connecting volume is needed. Flowing material balance (FMB) as a new approach in Production data analysis and Rate Transient Analysis (RTA) with a type curve will be used as the basis to determine the connecting volume from each well. Compared with conventional material balance where shut in is required to get the average reservoir pressure, FMB will use historical rate and flowing pressure to derive average reservoir pressure and determining connected Original Hydrocarbon in Place. By using FMB, it can also be seen whether the wells that have been producing interfere with each other thus have connecting volume between wells. All above solutions were preferable since no shut in is required. The results show Flowing Material Balance and Rate Transient Analysis give reliable connecting volume. The derived connecting volume then used to generate bubble maps as a guidance for estimating new well placements. The resulted maps, guided with the static model volumetric show the estimated drainage area and possible additional drainage from new wells to increase hydrocarbon recovery. Therefore, in W field 2 new wells have been proposed to be drilled in the following years.
Application Of Hybrid ESP-Gas Lift In Multilayer Carbonate Reservoir Of Ujung Pangkah East Java Offshore Field
Ujung Pangkah Offshore Field as the main oil & gas producing field of Pangkah PSC Block, has been produced from a total of 30-40 wells since 2007. The field has been using gas lift as its main artificial lift method considering the availability of gas rate to be injected and gas lift handling equipment capacity. However, the increase of more oil development wells & oil converted wells since 2019, all renders gas lift injection capacity considerably limited. Based on these constraints, in addition to the unused power availability from gas turbine generator, ESP (Electrical Submersible Pump) is decided to be trialed starting in 2020. X1 & X2 wells, formerly a gas-lift-enabled oil producing wells, are selected for ESP trial well candidates. These wells are both qualified to install and utilize ESP since these wells have relatively high productivity index and meet ESP artificial lift selection criteria. In addition to the usual ESP components (multistaged pump, motor, power cable, surface control equipment & Variable Speed Drive), gas lift valves inside gas lift mandrels are also installed above ESP system to enable contingent production with gas lift and to ensure the sustainability of well production rate when these ESP components experience trip/failure. To accommodate for ESP operation with pump maximum GOR limitation, these wells are also equipped with AGH (advance gas handler) and gas separator sub to remove free gas from produced fluid through annular venting valve. This annular venting valve & annular packer installations, as part of ESP completion, are one of the requirements to comply with company “well dual barrier policy”. Application of X1 ESP-GL conversion is conducted in Q3 2020, while X2 is conducted in Q1 2022. Even though it is being trial tested, X1 ESP pump has been running for almost 2 years to this day. Production rate increases with gain more than 348% in comparison to its depleted rate prior to ESP-GL installation, and saving up to 1.2 MMscfd additional gas lift rate capacity. X2 ESP yields gain to 38% of its last rate pre-ESP-GL installation, saving 1.1 MMscfd gas lift rate capacity. The conclusion is, the installation of hybrid ESP-GL system has been successfully applied in 2 wells in Ujung Pangkah field. For further strategy, another well is planned to be applied with the same hybrid ESP-GL system. Proper installation referring to fluid properties & production rate and proper operational procedure to maintain ESP pump run life is currently a key to maximize production opportunities particularly in limited offshore field.
Early Electric Submersible Pump Failure Detection Using Artificial Intelligence
Electric Submersible Pump (ESP) is a highly effective artificial lift method for boosting oil production in both onshore and offshore fields. The ESP maintenance will be conducted regularly as other artificial lift to prevent costly production disruptions due to unexpected pump failures. Many diagnostic methods have determined the ESP system’s status by using the automation system; however, these methods usually only provide backward-analysis after failure events have occurred. This paper involves acquired real-time data to establish an analytical methodology to detect impending ESP failures. The classification will be done on ten minutes-interval data forecasting performance, which shaped up into slope. This is primarily achieved using Supervised Learning Technique; Logistic Regression, Random Forest, Decision Trees, K-Nearest Neighbors, and Recurrent Neural Network Technique: Long-Short Term Memory. The models will be built based on individual distinct parameter’s characteristics of nine status consists of; low PI, pump wear, tubing leak, higher PI, increase in frequency, open choke, increase in water cut, sand ingestion, and closed valve with an accuracy rate over 90%. These automation and control systems require constant surveillance by a human operator to verify that all processes are running normally. Furthermore, the abnormal behavior is identified in advance, and the operators can early determine the best corrective action to avoid an ESP’s failure built upon the recommendations attached. It is the human perator’s responsibility to react to any alarm conditions that occur during operation. This introduced technology is an effective way to monitor the ESP system that leverages Artificial Intelligence. The operator can rely on the built surveillance system’s ability to detect abnormal behavior, allowing the operator to focus on higher priority tasks. Moreover, an engineer’s significant advantages are taking pre-emptive action to avoid failure and generating billions of revenues.
Initiation of MOFs Hybrid Membrane Development for CO2 Gas Separation
CO2 gas separation technology is the main technology that determines the success of Carbon Capture, Utilization, and Storage (CCUS) activities, so it needs to continue to be developed in a more effective and efficient direction. Membranes are one of the promising alternative CO2 separation technologies. Membrane technology can be developed using several materials, and what is currently being developed is Metal-Organic Frameworks (MOFs) because they have various advantages such as adjustable pore sizes and permanent properties. However, the cost of making MOFs material is still quite expensive, so further studies are needed. In this study, research was conducted to develop a hybrid MOFs membrane using a mixture of MOFs and polymer materials. Polymers are relatively inexpensive materials and can be used to bind MOFs so that mixed-matrix membranes (MMMs) are obtained, where the polymer is the matrix material, and the MOFs are the filler material. The development of hybrid MOFs begins with the synthesis and characterization of several MOFs materials, namely Zr(BDC) and Zr(BDC-NH2) followed by the synthesis of hybrid MOFs using PSf polymer. The MOFs hybrid membrane sheets were then tested on a laboratory scale to determine their ability to separate CO2 gas from CH4. Then a comparison was made between the CO2 and CH4 escape values from the pure polymer membrane and the MOFs hybrid membrane to determine the changes in permeability and selectivity that occurred. The test results showed an increase in the flux value of CO2 and CH4 in hybrid MOFs, where the increase in passed CO2 was far above that of passed CH4, so it can be concluded that the addition of filler MOFs succeeded in increasing the permeability and selectivity of the membrane. With the increased permeability and selectivity, it is hoped that the MOFs hybrid membrane can be used as a choice for CO2 separation technology in the future.
Laboratory Investigation of P and S Wave Types on Vibroseis EOR Technology for Low Permeability Reservoir
Advanced technology, specifically EOR, is needed because the reservoir still contains large amount of oil after the current oil is drained. Vibroseis EOR is one of the promising technologies under development. In its implementation, the attenuation of the S wave is lower than the P wave, so using the S wave as a vibration source will have a greater effect than using the P wave in increasing the oil recovery factor. Previous laboratory studies using circular mode vibration stimulation (S waves) revealed an increase in oil RF, porosity, and permeability as well as a decrease in Sor. The research objectives of increasing the recovery factor using both the vibroseismic method and water injection simultaneously are to explain the effect of transverse and longitudinal waves on vibroseismic and recovery factor (Sor) and also to evaluate the efficiency of water injection under the influence of transverse and longitudinal waves. According to this research, P-wave has a greater effect on increasing oil recovery than S-wave in low permeability. This experiment used a synthetic core with low to medium permeability at a frequency of 15 Hz and amplitudes of 0.1 µm for the P-wave and 0.2 µm for the S-wave. The Recovery Factor (RF) increment reached 8.3% on low permeability (34.8 md) and 10.29% on mid permeability (115.4 md) at same amplitude for P-wave. The increase in oil RF during vibration stimulation in circular mode occurs only at mid-permeability. This research was used in laboratory tests as well as the implementation of the EOR Vibroseis Field Trial in one of Pertamina's fields, and it was successful in increasing oil recovery in that field.
Centralization of Pertamina’s Drilling and Well Intervention Database with Dreamwell Application
One of the major issue in Pertamina Subholding Upstream is there is no centralized drilling database. Most of the data spreads in several different applications and is collected without further analysis. Seamless synergy in SHU can be aided by centralized data and daily drilling reports in a database system to aid in the effective and efficient integration of data management. Pertamina DreamWell Drilling Database is a website-based application that aims to centralize data consisting of drilling program, Authorization for Expenditure (AFE), daily drilling report, lesson learnt and Final Well Report. The offline version is also available in JSON format in order to anticipate the lack of internet network on some locations. Data can be accessed based on the role management system in the DreamWell app, by both SHU, region and zone Drilling Manager, Drilling Engineer, and Company Man. DreamWell app is supported by a Single Sign-On (SSO) system that is integrated with the email database in the Pertamina server, so it can be mapped based on the role management system. DreamWell app will generate output in the form of an interactive dashboard, well data, single well, and reports. Some examples of output results are well profile, GIS map, well schematic, time vs depth, drilling parameters graphs, PT/NPT pie chart, benchmark, lesson learned, etc. DreamWell app has additional features of drilling tools, including stuck pipe handling, well control, and economic fishing time worksheet. DreamWell app is a real-time application and also features a user-friendly display that allows the top management users to monitor data output efficiently, efficiently, and easily. Drilling data will be centralized in the application for analysis, which might serve as an early information source to aid in decision making during specific occurrences or situations that need decisions or policies (decision support system). Furthermore, this application aids in the collection of reliable data, allowing the suggested drilling program to be derived from the database's data assessment findings. Dreamwell is equipped with evaluation of cost and drilling performance monitoring. It is expected that drilling operations would run in accordance with the investment project's objectives or targets, in terms of on schedule, on budget, on scope, and on return (OTOBOSOR).
Auto Suction Chemical Pump (ASCP) is a game changer for Well Stimulation at Pertamina EP Subang Field
Injection wells are a vital part of the oil production process at Pertamina EP Subang Field. Regular acidizing treatment is needed to maintain the reliability of injection wells. The high cost of acidizing treatment for injection wells is a significant financial challenge. Therefore, innovation is required to make costs efficient by independently performing acidizing treatment with the same quality as using a stimulation unit. This tool, the "Auto Suction Chemical Pump" (ASCP), can function properly after conducting research, simulation, making prototypes and conducting various experiments. After completing tests with good results, tools with upscaling sizes were fabricated using SS 316 material for acidizing stimulation activities at injection wells at Pertamina EP Subang Field. ASCP is a game changer in performing acidizing treatment on injection wells because it does not require external power but uses injection power from the well itself. By performing regular acidizing, the reliability of injection wells can be maintained so that oil production activities take place optimally. In addition, acidizing treatment using ASCP can reduce operational costs because it does not require a stimulation unit rental.
Continuous Implementation of Well Integrity Management System Integrated with Online Application Module Bringing High Level Safety of Well Integrity in Pertamina Hulu Mahakam
Mahakam has more than 2500 wells with various type of well architecture and some of mature well has been exist more than 40 years. Well integrity becomes critical aspect to ensure proper containment as per well barriers philosophy. Since 2015, elaborate well integrity management system has been implemented in Mahakam and successfully maintained tremendous safety level of well integrity. The method used is by implementing NORSOK D.010 standard definition of well integrity which will be focusing on technical, operational and organizational approach. Furthermore, the online application system developed internally is also used as well database reference and well integrity classification by colour code. All information related to well barrier are recorded in one portal which are updated regularly. Standard operational procedure as one of the main reference also has been developed since 2015. Dedicated well integrity team, engineering in town and operation team are also established. Detailed monitoring and frequency is also precisely determine as per reference. It is concluded that well integrity management system in Pertamina Hulu Mahakam has significant advantages to maintain high level safety aspect of well integrity without any uncontrolled hydrocarbon leak to environment. The integration between technical, operational, organizational and also online module application is proven as a robust method.
Success Story of Optimization Low-Quality Reservoir in “R” Field at WK Rokan by Deliver Inclining Field Production Performance
Improving recovery in complex multilayer reservoirs of the mature oil field is one challenging task, particularly for those comprising various reservoir qualities with lateral heterogeneity characterization. Rigorous evaluation is required to define the best approach for production from the reservoir level into wellbore completion strategy. The sand with high quality would have significantly distinct flow performance compared to low quality with low permeability, which impacts artificial lift and perforation strategy design. Some common issues found were low rates, crossflow due to commingling perforation of contrast reservoir quality, where low-quality one could not contribute fluid production that sometimes by pressure difference block or permeability contrast. This paper undertakes this issue and discusses a case study of "R" field optimization strategy to improve production in the low-quality reservoir. “R” field is in primary recovery and characterized by two types of sand, high quality-permeability sand (HQ) and low quality-permeability sand (LQ). Most of its production comes from the HQ ("MT_R" and "BT340") and currently contributes to high water cut. On the other hand, oil from LQ with lateral permeability variations is unable to be produced optimally, especially when LQ is comingle with HQ, and opening LQ itself will be difficult to deliver fluid production. Lookback show LQ has low PI and is only able to produce with fracturing methods or commingled with HQ Sand. The full-field subsurface evaluation was conducted including detailed rates by reservoir perforation to acquire and confirm alignment between production and geological data, for instance, pay and permeability data. It has resulted in a new workover strategy to optimize "R" field including commingling several LQ, and reactivation of LQ at long-term closed wells. Pilot tests of commingling several layers of LQ usefully added fluid production with a low-rate pump and proved to successfully deliver a good workover result. Pilot tests were conducted at R#07, R#17, and R#39 with average fluid production of ~550 BFPD. The 1st batch workover produced oil gain ~300 BOPD and reduced fluid by 1,800 BFPD. The strategy has gradually been applied throughout the “R” field following lessons learned and success workover. The new strategy has been implemented in three perforations and six reactivations. The collaborative effort successfully improves underperforming wells and puts the long-term closed wells back to life. It delivers inclining field production performance with incremental oil up to 943 bbl/day, water shut-off ~4,500 BFPD from active wells with >70% success ratio. Bypassed oil from the LQ reservoir can be optimally produced by commingle several layers of LQ using a low-rate pump. Added value not only optimizes the underperformed wells but also better utilizes idle wells by unlocking the reactivation opportunities. This strategy has the advantage of delivering R2R2P through simple workover with cost-effectiveness.
Water Management Strategy in Brown Field, Case Study Prabumulih Field: Plan of Sustainable Development, Cost-Effective Implementation, and Zero Discharge
Water production has been a major operational issue that was closely related to oil production activities. It is one of the most challenging issues in Prabumulih Field that is categorized as Brown Field. The main reason is the difficulty on maintaining oil production by implementing a strategy to reduce water production. Therefore, a comprehensive strategy was needed to be able to implement appropriate water management. There are several obstacles regarding the implementation of appropriate water management in this case: production facility, budget limitation, fluid properties, subsurface condition, and social problems. Hence, a multidisciplinary team, subsurface and surface, is involved to arrange a comprehensive strategy for solving the issues. Subsequently, the strategy to overcome water-management issues is divided into four phases: planning, execution, monitoring, and evaluation phase. The planning consists of evaluating the matrix risk, determining of the priority level, making work program (short-term, medium-term, and long-term), setting the target, and determining the person in charge. The execution is conducted based on grouping the work program that has similarities (scope of work and location) and alignment with plan of further development.Accordingly, monitoring and evaluation are conducted to observe the progress and the accomplishment of the project periodically. This strategy has been implemented since 2018. According to this case, it discovers that every phase of the strategy has its own level of complexity. The challenge encountered in the planning phase is how to align budget limitations and program priority. Whereas the most challenging phase is the execution phase. Thus, because Prabumulih Field has a large area. Firstly, obstacles related to the social problem must be resolved before work program is executed. The interconnection strategy is conducted to reduce complexity in the execution phase and cost-effectiveness. As a result, it is proved as the best way for operation mapping and reducing costs. Furthermore, the interconnection strategy also provides a simplification overview for monitoring and evaluating the project’s progress. Besides, it helps immensely to monitor and evaluate based on every interconnection project. Finally, the water management problem begins to be resolved gradually in a more planned manner and is easier to align with Plan of Sustainable Development, as well as the long-term reliability of the zero- discharge program can be assured.
The Impact Of AARF (Abandonment And Restoration Funds) Obligation Toward Block Economical Aspect For Contractor Who Taking It Over Previous Non- Obliged Production Sharing Contract (Case In The “B” Block In Aceh)
The objective of this paper is to endorse some concerns about the transition of implementing Peraturan Menteri ESDM No.15 Year 2018 ("Permen 15/2018") considering the right & obligation in existing and previous Production Sharing Contract ("PSC"). The obligation of Contractor to do site restoration has no objection, but the Permen 15/2018 requires an installment targeting the total amount of abandonment and restoration by the time it will be performed. It seems not fair for the New Contractor (in case of termination) since the previous PSC was not required to deposit the fund. It means the new Contractor who performs the restoration will spend higher site restoration cost compared to the benefit they get from the block. The method that the writer is going to use in this paper is by running a simulation of 'fund obligation' starting from the usage of the assets or facilities until it will be abandoned. The facilities here mean everything needs to be restored, such as processing facilities, drilling/well facilities, pipelines, flowlines, and other supporting facilities. Even though the fund is not obliged to collect (for Old Contractor), the obligation and responsibility of Contractor to do site restoration is a must. Indeed, it is in the PSC (section right and obligation). Furthermore, the Old Contractor had already 'taken more benefit' from the block which should be in line with the responsibility for the environment. By running this simulation, the writer found that the new Contractor suffers most of the restoration cost. The facility itself was built around the 1970s, the block would had been expired in 2018 and the handover of the entire Participating Interest was done in 2015 when the block produce only the remaining tail gas. The installment of AARF was started in 2016. It is forecasted the facilities to be abandoned entirely during the period of New Contractor operatorship which means 100% of the fund of the New Contractor. The conclusion of this paper is the obligation of keeping the environment safe and clean is obliged to each and everyone on the planet. Especially in Indonesia, it is stated in the PSC and the Law. To reach this, the writer has some recommendations: 1. Government shall persuade all the stakeholders, especially the Old Contractor to comply with this obligation. 2. Even though the obligation of fund installment does not commit the Old Contractor, it could be calculated linear based on the operatorship period to see the relative fund the Old Contractor ‘responsible’ for the block. This study had been initially discussed with the Old Contractor, but neither commitment nor agreement reached yet until now to the above ASR obligation.
Bio-Surfactants with Various Types of Functional Groups of Fatty Acid Derivatives from Palm Oil which can be applied as EOR Surfactants from Low to High Temperature Reservoirs
Despite the sustainable development of energy sources, crude oil and natural gas resources remain important elements of the international economy. With global demand for petroleum and liquid fuels continuing to increase, increasing the efficiency of extraction from existing petroleum reserves is of paramount importance as the world gradually shifts from fossil fuels to more sustainable sources. To that end, Enhanced Oil Recovery (EOR) techniques have been developed and used to minimize the amount of crude oil and petroleum left in underground reservoirs from conventional drilling extraction methods. Surfactants that are widely used in the implementation of EOR are mostly petroleum-based which have challenges from availability, so that many studies have carried out the synthesis of surfactants using palm oil-derived fatty acids as hydrophobic groups and various functional groups as hydrophilic groups. In this paper, three types of surfactants derived from palm oil will be testing, namely Alkyl Ester Alkoxy, Alkyl Ether Alkoxy, and Internal Ketone Sulfonate surfactants. The surfactants were filtered at 5000, 18000, and 20000 ppm salinity conditions at 60 and 110 °C. Screening carried out includes compatibility tests, IFT, and thermal stability. The type of oil used varies for each surfactant, namely the type of medium oil with 34.39 °API and heavy with 24.8 °API. Based on experiments that have been carried out in the laboratory where Alkoxy Surfactants are surfactants that were tested at 1800 ppm salinity, 60 °C temperature, and 34.39 °API oil, they were able to produce IFT values up to 10-3 dyne/cm, with slightly cloudy compatibility. However, for thermal stability, this surfactant can only last up to 1 month. Whereas the Alkyl Ether Alkoxy surfactants which were tested under the same conditions were able to survive for 3 months of heating. In contrast to the Internal Ketone Sulfonate surfactant formula, the test was carried out at 20000 ppm salinity, 110 °C temperature, and heavy oil with 24.8 °API. Experiments carried out in the laboratory represent that the performance of surfactants derived from plants is capable of providing an IFT value of up to 10 dyne/cm, with slightly cloudy compatibility, and able to stable no degraded up to 3 months of thermal stability testing. This shows experimentally and chemically structure, surfactants derived from vegetable materials can be applied as Chemical EOR up to a high-temperature reservoir of 110 °C. The activity of a surfactant does not only depend on where the raw material comes from but how the structure and functional groups are created from the raw material to produce surfactant molecules that have powerful abilities. However, it is important to note that each type of surfactant with the same functional group but different carbon chain lengths and skeletal shapes will produce very different performances.
Evaluation and Hydraulic Fracturing Design for Optimization of Effective Conductivity in Multilayer Reservoir
The HI-68 is an existing well carried out by the fracturing program in layer A1 at an interval of 1254 – 1260 m. In this work, the fracturing fluid was pumped at a rate of 17 bpm and an average tubing pressure of 2000 psi, using 70 klbs carbolite proppant size 20/40 at a concentration of 1 to 8 ppa ramp and followed by a 30 bbl flush (under displacement 4 bbl) using slickwater. Hydraulic fracturing in the HI-68 was carried out 2 times, but the well did not experience a significant increase in oil, but there was an increase in watercut. This condition occurs as a result of hydraulic fracturing which results in low fracture conductivity. This is due to the problem of low fluid efficiency and the type of completion of the multilayer reservoir which results in unwanted early screen outs. Furthermore, the HI-68 well was modified for a limited entry multilayer completion in order to easily control fracture initiation which aims to reduce fluid loss into the rock, fracture initiation is a modification of the conventional method of hydraulic fracturing which is initiated by pressure, not velocity. Using rate to create pressure (as a consequence of Darcy's law). As the pressure increases, fracturing will begin as the pressure rises above the breakdown pressure of the weakest point along the hollow interval. The perforation interval 1254 – 1270 m has different price values and is divided into three areas, first interval area 1254 – 1260 m, second interval area 1260 – 1265 m and third interval area is 1265 – 1270 m, if the three areas are carried out hydraulic concurrent fracturing, it is possible for an early screen out to occur due to narrowing in the second interval area due to the stress load generated from the first and third areas which suppresses the second interval area so that fracture initiation does not develop. Using medium to high density proppant will be advantageous, because it is expected to form short and wide fractures with high conductivity around the wellbore. Results of sensitivity the proppant size larger than mesh size of proppant, resulting greater retained permeability, it will affect fracture conductivity value. From the economic aspect, the net present value for 1 year obtained depends on the fracture conductivity, so the combination of proppant type and proppant size is adjusted to the formation permeability conditions.
Rejuvenate Brown Field with the Characteristic of Lenses Reservoirs and Securing New Wells Net Present Va l u e U p b y P e r f o r m i n g I n -House Holistic Study
S-Structure, an area operated by PT PERTAMINA EP, has been producing oil and gas since 1976 and located in Upper Kutai Basin which is famous with lenses reservoir characteristics. Inspite of the challenges S-Structure faced in 2013 until early 2018 where production decline was severe and 5 previous drilled wells were considerably dry, it awoke again by a successful 989-bopd-drill well in 2019. There were two Final Investment Decisions (FID) made to finally effectuate drilling again in S-Field. Nonetheless, the first FID was a concern due two unexpected shale out and unprognosed gas layers and accordingly contributed minus Net Present Value (NPV) and the second FID consisting of 15 new well candidates got cancelled. Therefore, this study was conducted to tackle this hesitation. Subsequent to implemented method, we got approval for the 2 FID. The analysis was safely done without incidents and secure 15 wells to still be viable to drill. We divided S-Structure into sectors of Graben, West Panel, and East Panel which have their own behaviors, properties and productivity and we set minimum distances over offset wells afterwards. Within almost a year there were 5 new wells POP-ed with the total NPV and reserves realization are USD 7.58 million and 483 thousand stock tank barrels oil respectively. The method implemented is thorough and well suited with small tanks in such S-Strcuture. The result somehow creates positivity and encouragement to all members to stay striving towards profitable and efficient development strategy. New well proposals are designed through static and dynamic model generally speaking. However, it has always been a different approach when it comes to lenses reservoir type. There are plethora of costly methods to reduce subsurface uncertainties, yet during the time of the field is considered marginal, efficiency is the most profound and considerable action. Therefore, this method was developed consistently in-house with almost zero investment budget.
Thru-Tubing Ceramic Screen Application to Unlock Mature Sandy Well Efficiently: Successful Implementation in Sisi Nubi Field
Controlling sand production from shallow gas reservoir(s) is a challenge. Sand control is needed to avoid wellbore productivity damage and excessive sand production on the surface. Sisi Nubi is a gas field located in 25 km offshore from Mahakam delta. Most Sisi Nubi wells are completed with sand control in primary well completion to minimize sand production. Thru-Tubing Ceramic Screen (TTCS) is a new sand control method used in Mahakam. Ceramic screen was selected as it has higher durability and resistance against erosion than metal screen. Previous application in the swamp area shows good indication, thus encouraging further application offshore. Therefore, the objective of this paper is to perform the first trial of three joints TTCS implementation in offshore Mahakam field and unlock well potential to produce more than 3 MMscfd by applying thru-tubing ceramic screen (TTCS). In this project, TTCS was utilized in a new perforated shallow reservoir in Sisi Nubi, NX-Y. The installation involved isolating water producing zone, perforating reservoir target, setting three joints of thru-tubing ceramic screen in front of perforation interval, and cleaning up the well with sand filter. However, this was the first trial of three joints TTCS, as previously only one or two joints installed. As per previous experience, one joint can only accommodate 3 – 4 MMscfd to maintain operating in safe working envelope area. Since targeted reservoir indicates higher potential (i.e. > 4 MMscfd), three joints of thru-tubing ceramic screen was implemented for the first time. In order to ensure TTCS execute properly, well ramp-up was performed step by step to form natural packing between the screen and the wellbore supported by fixed acoustic sand detection to monitor sand production. As a result, NX-Y well succeed to produce up to 10 MMscfd which is more than 300% from initial target with sand free indication. Furthermore, this successful trial potentially leads to other implementations in Mahakam offshore further.
Integrated Reservoir Characteristics And Production Enhancement Strategy Of Tight Oil Reservoir In Upper Talang Akar Formation Case Study Limau Field – South Sumatera Basin
Low quality and tight oil reservoir is a crude oil contained in low permeability formation, including but not limited to shale. Oil reservoir with low quality and tight was initially unattractive to be developed, it is very low porosity (< 10%), very low permeability (<0.2 mD) and high water saturation (>95%) but eventually given unpredictable oil production performance Every low quality and tight oil reservoir is unique and field development should be determined based on individual petrophysical attributes, reservoir characteristic and production enhancement strategy. In this paper, reservoir and production characteristics of low quality and tight oil reservoir are summarized, the investigated reservoirs include calcareous sandstone reservoir in Upper Talang Akar Formation, AN Structure. Almost mud logging data unit is also captured very low gas reading (only up to C3) and no traces oil show during drilling activity. Pressure measurement using wireline formation test (XPT) and modular dynamic tester (MDT) is also confirmed loss seal and supercharged. The primary key evaluation that have led to identify hydrocarbon in tight oil reservoir on this paper are : a. Petrophysics interpretation attributes is optimized by Dipole Shear Sonic Imager (DSI) and surrounding well data analogy. b. Certain criteria were used to select the pilot well test such as gas chromatograph or formation cutting log, nearby well correlation, single open hole log and the distance from key well refference. c. Acid solubility data labtest as critical part of production enhancement strategy The result of petrophysic optimization is given more optimistic water saturation, but reservoir properties such as permeability and porosity is still needed to be enhanced. As primary recovery is quite low in tight oil reservoirs, the production enhancement strategy is necessary and it must be conducted based on a deep understanding of petrophysical and minerals contained in the rock matrix. Deep penetration of matrix stimulation HCl 15% seems the best fit in this case.As a result 8 idle wells were perforated and stimulated HCl 15% during 2019 - 2021. It has been an attractive oil production result with incremental reach to 822 Bopd, 45 - 60% water cut and 247 MSTB oil production cumulative. Well stimulation job has to be conducted periodically to maintain stiff production decline By understanding the characteristics of tight oil reservoir and proper production enhancement strategy, this paper can be expected engineers to unlock potential hydrocarbon and increasing the production,
View Biostratigraphy as A Useful Tool for Hydrocarbon Exploration – case from the Pre-Tertiary Sediment in the Bird’s Head Region, Papua
Biostratigraphy plays an important role in hydrocarbon exploration as a way to determine sedimentation ages and to give insights into sedimentary environments. However, little is known about the importance of biostratigraphy in hydrocarbon exploration. This paper focuses on the role of biostratigraphy as a useful tool for hydrocarbon exploration to support the search for new hydrocarbon reserves in Indonesia. We presented a case from the Lemigas Stratigraphy Group study on the pre-Tertiary sediment of the Bird’s Head in Papua as an example. This study aims to provide a better understanding of the pre-Tertiary sedimentary stratigraphy by providing a zonal division of age and depositional environment of the sediment of the study area. The biostratigraphy including foraminiferal, nannoplankton and palynological analyses, was performed on surface samples from the Sungai Ainim traverse, in Ayata Village, Meibrat Region, West Papua and subsurface samples (Wells W-1, S-1, A-2, M-1, O-1, W-4, R-1 and V-1). Overall, this study revealed five chronostratigraphic frameworks, including Permian-Triassic, Middle Jurassic, Late Jurassic, Early Cretaceous, and Late Cretaceous. The depositional environment initially occurred in a non-marine setting during the Permian-Triassic age. The Early Jurassic age is recorded as a hiatus. Subsequently, the Middle Jurassic is deposited in a nonmarine environment. The environment then shifted to a marine setting during the Late Jurassic age. The sediment succession disappeared during the Early Cretaceous age due to massive erosion. Finally, the Late Cretaceous environment was deposited in a marine setting. From the biostratigraphic data, we provide an insight into the role of sedimentary age and depositional environment in the framework of petroleum geology. Our findings show that the shale Ainim Formation in the Permian-Triassic age serves as a primary source rock, while the fluvial sandstone of the Tipuma Formation in the Middle Jurassic is considered the main reservoir. The occurrence of deep marine shale formed a caprock during the Late Jurassic age. Finally, the deep marina shale of the Jass Formation in the Late Cretaceous acted as a caprock element in the petroleum system. The outcome of this research shows that biostratigraphy plays an important role in the construction of geological models for hydrocarbon exploration. It has become a useful tool to support the search for new reserves, especially in the Eastern part of Indonesia.
The Implementation of Supervised Learning and Cloud-Based Technology for Petrophysics: Identification of Hydrocarbon Prospect Zone and Classification of Rock Facies
The evolution of oil and gas industry technology has always been improving through time. The fluctuations, uncertainties, and investments had never been higher than the present. The combination of these conditions gave birth to the high risk and high return nature of Oil and Gas Industries, specifically in the Exploration and Production (E&P) activities. In E&P activities, one of the important analyses that has to be done was Petrophysics. Petrophysical analysis in E&P activities, were still using an archaic and lagging method with certain problems in prediction accuracy and rapid analysis. Thus, data-driven methods were expected to solve this challenge with machine learning (ML) techniques that could be applied to determine hydrocarbon prospect zones within the best acceptable accuracy range. In this study, the proposed solution utilizes data from Volve Oil Field, North Sea. This field potentially derive an advanced petrophysical model comparable to interpreted trends in seismic data and stratigraphic sequences due to their subsurface complexity. In this paper, variations of ML techniques have been implemented to build the models that predict the hydrocarbon prospect zone through petrophysical analysis and classify the rock facies. The proposed solution is examined through the evaluation process of 5 wells and compares the best algorithms of 4 options such as XGBoost, Extra Trees, and Random Forest, LightGBM. This solution contributes to reservoir characterization through the accomplished multi-well petrophysical analysis by high accuracy in just seconds. The prediction of petrophysical analysis obtained accuracy above 90% (including of permeability, water saturation, and effective porosity); rock facies reaches 80,0% (multiclass data up to 9 labels) using LightGBM Algorithm; meanwhile, the hydrocarbon prospect zone reaches 95,6% (binary data) using ExtraTreesClassifier algorithm. The processing time is calculated in a range of 0.2 - 1.5 seconds separated by training and testing data under an 8:2 ratio. Our models are in development using cloud computing technologies, accessible by nearly any device in any location, so long as there are internet connections available, giving the flexibility to utilize features previously unavailable online. The use of cloud computing and artificial intelligence technology, which is compatible and in sync with the development of this solution, can further increase the value, flexibility, and usability of primarily GGR data. The combination of the best efficiency and accuracy allows for better planning and execution of POD's, aid GGR engineers in finding prospect zones and locating recommended new well faster, which can further increase the economy, scalability, and accuracy of the hydrocarbon zone prediction.
Prediction of Skin Factor Reduction and Production Enhancement of Gas Well in The Field based on CoreNovel Stimulation Chemical Compatibility Test in Laboratory
The article is focused on studying the condition of the physical properties of the reservoir rock before and after being injected with HPWBM (High Performance Water-Based Mud) and stimulated by Novel Chemical refers to the core compatibility test in the laboratory. Hereafter, calculations are carried out to predict the estimated skin factor reduction and production enhancement of gas well in the field based on the laboratory results. The next step is testing liquid permeability using KCL, this test is carried out before and after HPWBM injection and novel chemical injection. Therefore, the physical properties of the core were obtained before and after HPWBM and novel chemical treatment. Based on the core permeability value, the skin factor calculation was performed after HPWBM invasion and after injection of novel chemical with Tarek Ahmed (2001) equation, then nodal analysis was calculated to predict the increase in gas well production rate after treatment with novel chemical. The results of core permeability after being injected with HPWBM filtrate was decreased from 8.56 mD to 1.56 mD, which indicates that the invasion of the mud filtrate can cause damage in the borehole, then the core permeability after being injected with novel chemical shows an increase from 1.56 mD to 3.79 mD, this proves that novel chemical is able to reduce damage to rocks. Based on estimation of the skin calculations and well production rate results, it is shown that the novel chemical is predicted to be able to reduce gas well skins caused by HPWBM filtrate by reducing skin by 72% and able to produce with an estimated gas flow rate of 1.2 MMscfd.
Breakthrough Completion by Applying Monobore Completion Well Design on SKL-XXX Well
Since Pertamina internal reorganization, Pertamina EP Asset 5 joined within Pertamina Hulu Indonesia (PHI) group, following PHSS, PHM, and PHKT. Since long time ago, Pertamina EP Asset 5 applies conventional completion design (7 inch liner with 2-7/8 inch tubing inside) meanwhile PHSS, PHM, and PHKT already applied Monobore/dual Monobore completion design (cemented 4-1/2 inch or 3-1/2 inch tubing inside open hole) for well duration and cost optimization in their wells for years. Noticing Monobore completion design was proven for well duration and cost optimization, Pertamina EP Asset 5 adopted their success story by replicating Monobore completion design to apply in well SKL-XXX located in Zone 9 as a pilot project. From preliminary study, the application of Monobore completion design in SKL-XXX was expected to optimize cost at around of 190 KUSD and faster drilling time by 3.4 days. During project execution, trial of Monobore completion was successfully applied without major operational problem and delivered actual cost saving at around 99 KUSD and faster completion duration at around 1.6 days compared to conventional completion. This success story of trial Monobore completion at SKL-XXX has been proven as alternative for optimization improvement in the future and opens opportunity to deploy Monobore completion design in all Asset of Pertamina EP.
Breakthrough Application of Encapsulated NaCl Polyamine High Performance Water Based Drilling Fluids System in Mahakam Field, Indonesia
Pertamina Hulu Mahakam (PHM), operating in Mahakam Field, has been drilling 321 wells for swamp operation and 73 wells for offshore operation. Surface section of the wells were drilled using conventional Potassium Chloride (KCl) Polymer System as inhibitive drilling fluids is needed to overcome reactive clay formation. Failed to overcome reactive clay might cause wellbore instability problems which will increase potential shallow gas hazard. However, in 2022, price of KCl has soared to highest level by 200% increased due to its scarcity. This is a consequence of ongoing political issue happened in Belarus. The challenge presented as alternative water-based system should be implemented to replace KCl Polymer System to maintain well cost economically. Study of Encapsulated Sodium Chloride (NaCl) High Performance Water-based Mud (HPWBM) System has been executed as an alternative to KCl Polymer System. The basic idea is to replace shale inhibition method from using Potassium Chloride to Polyamine. Extensive laboratory testing was carried out to evaluate the performance of Encapsulated NaCl HPWBM and ensure it can generate similar or better performance compared to KCl/polymer system. Using cutting samples from Sisi field, KCl Polymer Mud and Encapsulated NaCl HPWBM with various concentration are prepared and tested to evaluate its inhibition performance. X-ray diffraction (XRD) and Cation Exchange Capacity (CEC) analysis were conducted to identify the type, relative amount, and reactivity of shale minerals present in sample. Encapsulated NaCl HPWBM System has been applied successfully in 12 trial wells on offshore operation with total depth up to 1,800 meters. Through the implementation of Encapsulated NaCl HPWBM, dilution rate has vastly reduced by over 78% and hence, cost saving over $180K has been achieved. This has shown potential cost efficiency with more surface section to be drilled in this year.
Case History of Unique Dual Cutting Eccentric Reamer to Address Poor Wellbore Condition While Reducing NonProductive Time in Drilling Operation Indonesia
Historically the main focus of cost reduction and drilling improvement exercises has been to focus on reducing on-bottom time by improving ROP and drilling entire hole sections with a single bit. This has been so successful that in most cases only minor additional improvements are available and the potential cost reductions are much smaller. However, there has been less attention on reducing the time when the bit is not on bottom such as trips, wiper trips, backreaming, etc. When this time is analyzed in detail it becomes apparent that much of it is spent improving the quality of the wellbore to facilitate tripping and running casing or liner. This is where significant savings can still be made and such simple tool need to be added in the BHA to address the wellbore conditioning issue. The paper discusses some cases of drilling operation in Indonesia where the hole sections are considered challenging such as Pipe stall, overpull, stuck pipe, and tight spots that are typically experienced during drilling and tripping. It also results in difficult trip-out BHA and subsequent trip-in with casing. A unique dual cutting eccentric reamer tool was introduced to help to improve the wellbore quality. The tool removes or smooths out irregularities in the wellbore geometry during drilling and reaming operations. After several case, the tool solved many cases of wellbore condition issues. In one of west java drilling operation, the time savings in pulling out of hole was improved by average 78% in the 12¼-in. section and average 45% in the 17½-in. While in delta mahakam drilling operation, the tripping speed of the BHA is improved from average 82 m/hr to 192 m/hr (or about 139% improvement). In addition to that, the tool has also solved some cases to facilitate tripping in casing to designated depth. Ultimately, the tool has added a new capability for drilling improvement and optimization through wellbore conditioning, removing risk of pipe stuck, reducing non-productive time and interval costs which ultimately contributes to lower drilling cost.
Unlocking Production Enhancement in Onshore Monobore Completion with Mechanical Artificial Lift
Monobore was implemented in PHSS since 1996, replacing conventional completion to reduce drilling cost and simplified rigless well intervention. today, more than 500 monobore wells has been completed. This project is expected to give at least 80BOPD gain per well, increasing production reliability, and economically profitable for company. During the lifecycle of the well, Natural Flow will be the first method to exploit hydrocarbon from a reservoir. Later on, in extended NF period, gaslift could be used to modify wellbore liquid in order to be lifted by its pressure. As reservoir getting depleted, and watercut started to increase, at some point, GL will not be effective to make the well flow at stable rate. This period, as experienced by PHSS for some years back, has raised the sense of urgency to implement mechanical pumps, especially on monobore wells. The main challenge is that slim monobore completion was designed to accommodate NF and GL well, but will give some limitations for mechanical pumps. Small wellbore diameter, absence of annulus and tight wellhead footprint in dual monobore completion, with additional equipment required to insert downhole pumps and sucker rod has to be addressed to solve the issue instead of adding future complexions. Due to the lack of monobore wells with mechanical pumps in Indonesia, references are limited and pumps will be fabricated and shipped from overseas. Thus, well data and forecast has to be taken into account, since the pumps will ready at least 6 months after finalized design. At first, well with liquid gross increment opportunity was chosen, not included those with sand/solid problems, as it is the major threat for mechanical pumps. Then, similar candidate are organized to finally came up with candidate tiers ranking. Lab test was also conducted, in together with gathering updated data from well reactivation attempts. Discussion with service companies was done simultaneously to grab knowledge and evaluate artificial lift limitation in fluid tolerances, downhole pump capacity, surface footprint, power requirement and simplicity to conduct rigless operation. Finally, economic analysis and procurement strategy was developed to ensure company satisfaction in trial period while stay fair to vendor Thru Tubing ESP and insert-PCP has been decided to be implemented to replace Permanent Coiled Tubing Gaslift (PCTGL) as current artificial lift. One major classification is TTESP will be use in dual monobore completion while iPCP is for single monobore due to surface footprint and economic consideration. 15 well is identified to be TTESP candidate in 3 Tiers, and <10 wells as iPCP candidates. This tier ranking system will provide candidate “backup” for every tier, that will simplify procurement and evaluation process.
Sand erosion detection by In-service Ultrasonic Testing to prevent hydrocarbon leak at wellhead choke valve in Handil Field – Pertamina Hulu Mahakam
Handil field is a mature oil field located in the Mahakam delta that has been in production since 1975. Following its natural decline, sand production management is a challenge that cannot be avoided to sustain the Handil field oil and gas production. About 65% of Handil field production comes from a high-risk sand production well category. As part of the sand production monitoring strategy, the choke valve verification program is carried out regularly to identify the erosion due to sand which may lead to hydrocarbon leaks. However, this approach has a few limitations and requires a well shut down. This paper discusses a new method to detect sand erosion at the choke valve by using an In-service Ultrasonic test (UT) implemented in the Handil field. In-service choke inspection by Ultrasonic Testing (so-called iCIUT) is an innovation implemented to avoid hydrocarbon leaks due to sand erosion by early detection of the erosion sign and potential escalation at the internal part of the wellhead choke without production losses impact. A new methodology to improve the existing manual choke verification is introduced in 2019. This method promotes the utilization of ultrasonic testing to resolve the limitations to identifying erosion of the inaccessible internal part of the choke valve. The ability to conduct in-service inspection provides a valuable benefit to avoid the need to shut down the well and production losses during the operation. This innovation has successfully identified a defect at the wellhead choke valve in more than 40 wells in the Handil field since 2019. It’s been proven capable of detecting erosion at the wellhead choke valve in advance, so hydrocarbon leaks can be prevented. The iCIUT method demonstrates advantages as follows: • Provides simple operation without the requirement for unit dismantling and a lifting equipment. • No production losses during the operation. • Estimate choke valve service life and replacement time. This iCIUT method opens an opportunity and low-cost operation to optimize production from shallow zone when a limited option is available for sand control installation or high-cost sand-resistant materials. On the other hand, it improves well operational efficiency and HSE wise.
Using an Economic Model for Assessing High-Risk Exploration Project, M and B PSC Assets, in Sumatra, Indonesia
In 2022 and the next few years, Energi Mega Persada will conduct the exploration projects campaign in several producing blocks including M and B to seek some potential upside for adding company book reserves. This exploration will consist of geological and geophysical seismic, acquisition, processing, and drilling. It’s estimated to spend a large capital investment so it’s needed justified economic modeling. High-risk projects including exploration are projects that are full of uncertainty and randomness, so the approach to the economic model is not enough with a predictable deterministic model, but also requires a stochastic model approach that takes into account the random factor. In the economic model that will be made, of course, it will consider risk in decision making, so to make it easier, a decision tree path is made M and B are assets that already have steady cash flow. In principle, the two blocks can finance all of their operating activities and set aside cash reserves for investment activities. But how much financial strength is there to pay for exploration activities and how to choose an exploration project that has a positive impact on the company needs to be looked at further and again the difference between the two types of PSC, namely M which uses gross split and B which uses cost recovery also has an effect on economic calculations. Economic modeling, both deterministic and stochastic, which are in principle opposite, has been used to view the project prospect in Energi Mega Persada, so that the project can be understood better, and can sort out projects that are economically disadvantaged.
Optimizing Surfactant Polymer Flooding: Integrated Study from Molecular Dynamics Simulation to Chemical Cost per Incremental Oil
The effectiveness of surfactant formulation to extract the trapped oil in the mature oil field has been studied for many years, especially in Indonesia where the majority of oil fields are on declining stage. The main objective of this research was to demonstrate how to develop excellent surfactant formulation along with polymer to maximize the production of oil. Surfactant formulation that in charge for lowering the interfacial tension (IFT) of oil and water, decrease the capillary forces and generating mobile oil consists of local biosurfactant derived from palm oil and commercially available co-surfactant to obtain synergistic mechanism of oil and water, whereas polymer is added to reduce the mobility ratio between displacing fluid and displaced fluid for improving sweep efficiency The study starting with molecular dynamics simulation to screen the potential biosurfactant and synthesizing the selected one. Synthesized biosurfactant was tested including IFT measurements, and phase behavior investigation at several formulations with various ratio and concentration of biosurfactant and co-surfactant to obtain the best surfactant formulation. Polymer was then added to evaluate the surfactant performances in representative standard core. The cost effective of surfactant polymer formulation to increase the oil production was also calculated. It was found that surfactant formulation which exhibiting the lowest IFT and the highest microemulsion consist of biosurfactant and co-surfactant with the ratio 1:1 (OFTD11) at a given salinity. A series of flooding experiment utilizing varies surfactant polymer formulation which performed on sandstone standard core showed that OFTD11 was able to obtain maximum oil recovery with injection of 0.3 PV surfactant polymer followed by 0.6 PV polymer resulting in recovery factor as high as 45.19 %IOIP (initial oil in place). It showed that the volume of microemulsion formation is directly proportional to the recovery factor of chemical flood, indicate the importance of microemulsion for optimum oil recovery. This high performance of chemical injection described from chemical injection cost as low as 1.42 USD/bbl chemicals injected or 4.52 USD/barrel incremental oil with the price of biosurfactant 4.17 USD/kg, co-surfactant 4.25 USD/kg and polymer 3.3 USD/kg. Systematic methods begin with molecular dynamics simulation to the economical chemical cost are required on developing the suitable chemical formulation that is specific for certain reservoir in order to achieve the cost effective chemical EOR application.
Black Gold From An Old Field: Redefining Methods To Revive Hydraulic Fracturing As An Effective Stimulation For Sangasanga's Tight Oil Potential
Generally, East Kalimantan reservoirs consist of deltaic sand bodies deposited as lenses with high heterogeneities. As the tight formations of these reservoirs are often uneconomical, some are left undeveloped due to the necessity of stimulation job. In addition, operators are typically faced withnumerous operational and technical challenges such as thin layer reservoirs, weak shale barriers, coal streaks, high pour-point oil, and over-pressure zones. Over the past decade, few major oil companies in this region have performed frac operations, with less than 10 wells fracced per year with varying and unpredictable results. Afterall, Sangasanga still has remaining reserves for further development. Fracturing efforts in this field are intended either to expedite production or proving up reserve. Over the last 8 years, 25 frac operations have been performed in more than 10 different formations. With limited data and low reservoir uniformity, statistical analysis is challenging as there are little to no trends in the key parameters. As a result, fracturing success ratio dropped from 70% to 30%, mainly because of inaccuracy and inconsistency between the predicted and actual results. A detailed review of previous fracturing design and execution was conducted to revise the fracturingapproach workflow. The main sequences are data normalization and applying unique coefficient of key parameters. Trial and error approach is used to match the coefficient against the production outcome. The results are then summarized in a simple yet conclusive graph. In addition, several key factors and cut-off values to consider when selecting fracturing candidates were identified. DFIT campaigns were also performed to gather data to help predict the fracturing outcome and plan for the operational resources required for execution.
Integrated Field Development Strategy for Offshore Mature Field - A Success Story from Bekapai Field
This paper presents the results of the exploitation strategy in the development of an offshore mature field. For Bekapai offshore mature field, the integration of the geology, reservoir, production and surface had allowed to define new opportunities for drilling, baseline production optimization and then to establishing a holistic development strategy of Bekapai field. Bekapai is a mature oil and gas field located in the offshore Mahakam Delta, Indonesia. Bekapai field was discovered in 1972, production commenced in July 1974 and the production peak was achieved in June 1978. The hydrocarbons are accumulated in a complex multilayered reservoir, where oil, gas and different reservoir pressure presence alternately. Reservoir heterogeneity, sand production from unconsolidated reservoirs, poor vertical lift performance (no artificial lift), increasing water cut, well integrity issue and ageing surface facilities are main challenges in Bekapai field. Today’s Bekapai development strategy therefore focuses on drilling projects, modification in several platforms for surface debottlenecking and gas lift compression project. Infill drilling activities which resumed recently give a very good result and contribute significantly to Bekapai field production. Next phase of drilling projects (conventional infill drilling, grid base drilling, deepening and step out drilling) and platform modification will be performed in 2022 and 2023 while gas lift compression project starts up expected in 2023. Tertiary oil recovery also considered as future development and long term project of Bekapai field. Other than future development projects, optimizing baseline production and well intervention contribution are important part to arrest the field production decline and prolong the life of the field. Improvement in exploitation strategy combine with synergy from multidisciplinary team have resulted in maintaining Bekapai field production decline and better realization of reserves replacement ratio, even after 50 years of production life. The success of these improvement efforts illustrates an extensive review of the various aspects of mature field development which proved to be an effective approach in optimizing production from a mature oil and gas field.
Effectiveness of Using 80 cm Cyclone Profile at The End of Suction Pipe After Sand Screen for Sand Separation at The Accessories of Tubing Pump
The Oil and Gas Industry is facing huge challenges, especially for mature field. Enhanced Oil Recovery (EOR) already used to maintain the reservoir pressure, so the crude oil still produced in accordance with its reserves, although artificial lift is needed. The other problems of mature field are sand and scale, mechanical accessories chosen to solve that because it is cheapest way. The data said the 73% of well services problem contributed from sand problem which cause pump stuck, leakage of ball and seat, and pump intake clog since the mud anchor is full of sand on sucker rod pump wells. The first mechanical accessories to solve the sand problem is using sand screen at the intake as the pump accessories. Based on the evaluation, sand screen in not effective to cure the problem. The sand still breaks through the pump. Additional accessories behind the sand screen are needed for sand separation. A cyclone profile with 80 cm length and 60 angle is pinned at the end of eight-meter suction pipe to separate the sand form production fluid, then the sand collected at three joints of mud anchor located at the end of tubing pump string. To prevent pump stuck, extension plunger and tungsten ball & seat are used. The installation of these accessories produces good result for overcoming sand problem. The two wells that uses these accessories had longer run life more than six months from before. The other good advantage is when the surface pumping unit at the surface is accidently shut down, the plunger of the pump did not stuck inside the barrel, so the production could continue. With this result, the accessories could prevent the sand from produced into the pump, and it is an effective tool to resolve the sand problem in mature field with less cost. The installation of 80 cm cyclone profile at the end of the suction pipe on tubing pump string is a practical solution with less cost for mature oil field that encounter sand problem as a common challenge in producing oil.
Exception Signal Improvement for More-Accurate Identification of High Tubing Pressure Well in Delta Field
Abstract. IEMS (Integrated Exception Management System) is integrated solution for exception management which applies data science process to organize large amount of data and automatically generate exception signals that are prioritized for review and actions. The scope is currently focused on reduce Lost Production Opportunities (LPO), optimizing wells by reducing time taken for abnormal conditions to be identified and anticipated. One of problems in Delta field is high tubing pressure that occurs due to upset of fluid to flow caused by restriction from pipeline. Exception signal to identify anomaly tubing pressure using data tubing pressure from dynamometer is mostly end up as “no further action” or false signal. Which mean, criteria or data science process in IEMS to captured high tubing pressure is not robust enough. For more accurate identification of high tubing pressure wells, team has applied to alter the maximum tubing pressure to average tubing pressure to capture fluctuation tubing pressure. Additional criteria added to strengthen the criteria is using Artificial Intelligent. Machine learning will be labeling and classification the dyno card to identify high tubing pressure identic with dyno shape with hump. The combination of these data, we expect to reduce false signal that related to resource’s manning hour and reduce potential hidden wells down. Recommendation for wells after high tubing pressure exception signal is flushing the pipeline with water. Several flushing requests are rejected by operation team due to normal tubing pressure. To avoid discrepancy data tubing pressure, we recommend for regular calibration pressure gauge or pressure transmitter.
Stages of Quality Control of Low Frequency Passive Seismic Data Acquisition: study case of NL area Sangasanga Field
In January 2022, passive seismic data acquisition using a three-component broadband seismometer was successfully completed at the NL area Sangasanga field. Commonly, LFPS acquisition uses surface seismometers equipment but in this study borehole seismometers were utilized to acquire the data at all stations planned. It was a challenging condition in the middle of active production of open pit mining (24 hours a day, 7 days a week). Some strategies of acquisition have been made to deal with surface noise (human activities) to ensure the quality of data prior to advanced data processing. Due to the usage of borehole seismometers thus the procedure in equipment deployment should be cleared and recorded in data acquisition particularly, azimuth or orientation of sensor, coupling sensor and level of sensor.Moreover, the quality control or daily data acquisition checking is also to be done including daily calibration, visual/ qualitative analysis of recorded data and polarization analysis. The classification of recorded data could be achieved after the three stages of quality checking were performed. The classification into three classes based on the length of good data from recorded data, result of polarization analysis, as well as the consistency of value in daily data calibration. From each analysis of data classification obtained that the repetition measurement was needed in several points and the analysis is expanded to VHSR analysis to tackle the dips results from polarization issues. Therefore, the result of this study is VHSR map and utilized to determine a new drilling proposed well VHSR value is higher than 0.3 is indicated as the hydrocarbon prospect. In addition, result of the delineation hydrocarbon prospect map from this study is quietly matched with the net sand map of the study area that was built from various data integrations.
PVT Quality Control Data On Retrograde Reservoir Fluid For Compositional Fluid Modeling
Quality control of PVT data from laboratory measurements needs to be done before the data is used for fluid models. PVT data with good quality will help in the validity of the fluid model. Quality control is done by calculating the Gas Oil/Condensate Ratio and STO Oil/Condensate Density on the model based on the composition of the hydrocarbon fluid. The calculation results are then compared with the prices of the Gas Oil/Condensate Ratio and STO Oil/Condensate Density measurement results. Then these results are used as the basis for making fluid models. To validate, this fluid model is used to create a well model for calculating vertical lift performance. Quality Control results show that there is a discrepancy in the GOR parameter of 27%, with a tolerance of 10%. For STO oil/condensate density of 0.08 gr/cc with a tolerance of 0.02 gr/cc. Because the results of the discrepancy are above the tolerance limit, adjustments are made by making a composition gradient that is adjusted to the GOR from laboratory measurements of 43411 SCF/STB. The results of the calculation of vertical lift performance obtained good results, with the difference to the slickline measurement data, the average is below 2%. This result is much better than the results of the well model using the black oil model. This paper describes the fluid model validation method by integrating several other supporting data in addition to only laboratory measurements.
A Success Strategy to Producing Thousands BOPD in Complex Pressure and Drive Mechanism Reservoir Conditions with Highly Uncertainty of Faulted Architecture Field in Rokan Block, Central Sumatera Basin
Depleted reservoir is becoming one of the challenges to be faced in mature oil field, especially when the pressure depletion is likely to fast comparing with similar oil field characteristics. TLN field (one of the prolific oil fields in the Rokan Block, Central Sumatera Basin) was one of successful example related to rapid reservoir pressure depletion. Pressure depletion in TLN field especially in MB block area was observed pretty rapid by latest pressure surveillance which caused by significant fluid withdrawn since 2003, which provoke to saturated reservoir conditions. Surprisingly, these depleted zones contributed 70% of total TLN field original oil in place and at its prime reservoir condition, MB block area was major contributor for oil production in TLN field particularly from PMT sands. This success story was accompanied to fulfill PT. Pertamina Hulu Rokan additional production and part of the 2021-2022 drilling campaign which two wells are proposed in TLN field. TLN field location approximately 30 km to the northwest of DRI field, which both operated by PT. Pertamina Hulu Rokan since August 2021. To manage the dynamic and geological uncertainty of TLN field, which led to success of producing thousands of BOPD in 2020-2021 drilling campaign, we develop a certain strategy that suits in TLN field. From the geological aspect, we re-utilize the fault interpretation to mitigate havoc in development and execution stages using seismic reprocessing, seismic enhancement, and seismic attributes. As mentioned above the dynamic characteristics of TLN MB Block reservoirs are quietly challenging due to the pressure depletion led to the high gas oil ratio, which can be observed from drive mechanism plot of TLN Field. Likewise, the combination of weak water drive mechanism and solution gas drive that both works in TLN field is a challenge to be mitigate before well execution begin. With robust subsurface concept that applied when develop these two proposed wells in TLN field and combining with reservoir management strategy when well execution began such as, producing only from single sand and considering ESP design to be installed with gas separator, we successfully to produced additional oil gain of approximately ~2800 bopd and unlocking future potential strategy to develop MB block of TLN field, respectively due to low reservoir pressure. As a lesson learned, we realized several strategies from geological aspect such as re-utilize the available seismic and generating seismic attribute similar like coherency to get higher resolution of fault plane location and fault continuity to mitigate the tructural uncertainty in developing and further when execution phase begins. Moreover, a robust reservoir management is mandatory to overcome low pressure reservoir which can lead to high gas oil ratio must be managed appropriate to avoid gas production instead of oil production.
Challenges and Mitigation Strategies for High Gas Situation during Drilling in Sapi Field
This paper discusses the challenges and mitigation strategies for dealing with high gas situations during Sapi development well drilling operations on Pertamina Hulu Kalimantan Timur. Sapi's drilling campaign began in December 2021, with three re-drill and four new wells. Historically, the highest record of gas encountered during drilling is 4,500 U TG and 1,000 U BG without a kick sign. The Sapi-13RD1 is used as the benchmark for the high gas situation in Sapi area during this campaign. This well encountered a high gas situation while displacing the well with mud from 12 ppg MW to 12.4 ppg at 13148 ft, BG reading increased from 180 U to 400 U. This situation induces confusion among operation and also drilling program design against material stock and drilling time efficiency despite the limitation of drilling cost.. As a result, new strategies for dealing with this situation were developed. Offset well studies show that increasing MW has been shown to reduce BG Gas in some cases, but not necessarily peak gas encountered during drilling. The SAPI-1 well was drilled to TD with a maximum of 14.5 ppg MW but still encountered up to 3000 U of connection gas. Despite maintaining adequate mud overbalance (max pore pressure SAPI- 13 is 8.7 ppg from MDT log), we still encountered high gas content during drilling. Following a thorough analysis of pore pressure-related events, the drilling history of all offset wells, and responding from the drilling operation side by ensuring safe drilling, the high gas reading is not related to pore pressure close to mud weight. The decision flowchart for high gas situations during drilling was made by increasing the cut off of BG gas to 400U prior to increasing MW and setting a cut off TG 2500 U to close annular and circ gas out. This decision flowchart was used for the remaining six wells in this campaign, giving the drilling team the confidence to accept the high gas reading while maintaining safe operation in the Sapi area. This decision record is developed to give clear guidelines when encountering high gas situation during drilling to ensure that the well can be safely drilled – maintaining well control at all times - without compromising other factors when we decide to increase the MW to specific value (risk of differential sticking, losses, ballooning, cement slurry weight strategy, etc)
Forecasting and Modelling Onshore Gas Reserves in IndonesiaUsing the Creaming Curve and Linear Regression Analysis
In early 2016, oil prices fell to its lowest level (30.32 US/bbl) over the last 12 years, and the coronavirus (Covid-19) outbreak that started at the end of 2019 has had a negative impact on the world economy (including the oil and gas industry). Since then, petroleum exploration and exploitation activities have decreased worldwide. The oil and gas companies must look for potential oil and gas reserves that can be produced and had to make extra cost savings and produce new strategies to avoid negative cash flow and keep the projects economically acceptable, such as: cost efficiency, proposed incentives (investment credit, interest cost recovery, etc.), proposed changes to the terms and conditions of the existing contract (depreciation acceleration, DMO holiday, share of First Tranche Petroleum (FTP), change of Split Ratio, etc.), etc. In terms of oil and gas reserves, this paper will assist the Contractors and the Government in determining the area that has the highest and the lowest number of gas reserves per project using the Creaming Curve and Linear Regression method by processing statistical data from 165 data (onshore gas projects), so that Contractor are able to analyze which area is economically acceptable for oil and gas activities. Based on the analysis of 165 onshore-gas reserves in Indonesia, Sulawesi is estimated to have the highest amount of onshore gas reserves by 521.90 BSCF per project, which means that these areas have become the most interesting areas for contractors to produce profitable gas projects. Meanwhile, Kalimantan is estimated to have the lowest mount of onshore gas reserves by 46.20 BSCF per project compared with other areas in Indonesia and this is because there are quite a lot of projects that are concentrated in one area (East Kalimantan) which causes the condition of reserves in that area to mature.
Precisely Production Forecast After Conducting Hydraulic Fracturing Using Water Cut And Ratio Cumulative Production - Total Water Injected Trend
Alfa Structure was established at 1982 and performed 2 drilling wells. There is only one well that have been producing since 1982 to present with 30 bopd and cumulative 429 MSTB. This well produce with tank on site due to the distance with existing location. This structure has not been developed for a long time, therefore in 2019 a seismic 3D survey was conducted. Subsurface opportunity appearance from this study. At least 7 wells plan were planned to be drilled to develop this structure. Main reservoir is Upper TAF with low resistivity and low quality reservoir therefore Hydraulic fracturing is a one of the proper methods to produce the well from Alfa Reservoir. More than 1000 bopd from 5 wells that has been drilled in 2021 and 2022 with using Hydraulic Fracturing method. Considering subsurface uncertainty to develop surface facilities, production forecast become essential especially in oil forecast. To monitor performance and forecast oil production after conducting Hydraulic Fracturing, this paper aims to share valuable field experience between Water Cut and comparation cumulative production - total water injected. Alfa Structure produced only 30 bopd previously, but currently become more than 1000 bopd after developing 5 wells infill drilling with using hydraulic fracturing. Every Infill drilling that is carried out by hydraulic fracturing at the beginning of the start-up of well production, the fluid that comes out is water that we inject into the reservoir when doing hydraulic fracturing. Total water injected comes from Breakdown test, Multi rate test, calibration test and Main fracturing. By the time production, water will decrease and oil comes up with following Water Cut and comparation cumulative production - total water injected trend. As the result, The existence of this trend will be a reference in every monitoring of well production after using hydraulic fracturing and with that we can estimate more precisely when the well will produce according to its potential and very useful in surface facilities planning.
Handling ESP Problem Using Automatic Frequency Rocking (AFR)
The most typical issue with ESP is a gas lock, which causes the system to stop down and need a restart. Due to motor fires, downthrusts, a damaged shaft, and other issues, the gas lock prevents production. Gas-lock is managed by avoiding, decreasing the effect of, and removing it. By employing a gas handler, choking, and venting, gas-lock may be prevented. However, these measures have not entirely prevented the gas-lock. Utilizing Inconel shafts, Hi-Temp motors, and high-quality materials have been attempted to make gas-lock less of a problem, but the issue has yet to be resolved. The conventional way for removing the gas lock is to switch off the ESP and restart it, however this generates further issues, such as the pump being stuck. In addition, for offshore activities, weather, boat availability, and distance must be considered in order to resume an ESP. Therefore, another way is required to remove the gas-lock without disabling the ESP. Changing the ESP frequency manually using variable speed drive (VSD) is a typical method for removing the gas-lock without turning off the ESP. By altering the frequency, it is anticipated that the trapped gas will be forced out of the pump by the fluid. However, changing the frequency manually is ineffective for offshore activities. Instead, an automated procedure is required for greater efficiency and quickness. A controller module rather than VSD operator personnel is needed. The controller comprises a PLC, an HMI display, and setup software. The frequency changer is activated by low-ampere, low-Pi, and high-TM plus delay time trigger factors. The frequency-changing process is halted depending on time or other criteria, indicating the elimination of the gas lock. If the sign of gas-lock is recognized, the procedure will resume. This method may be performed several times throughout the day and night. This technique is referred to as Automatic Frequency Rocking (AFR). The ESP installations at well CINE-09 were observed. The run life of the last four ESP placed in the CINE09 well is 71 days, 29 days, 39 days, and 335 days following the use of automated frequency changer AFR. The issue with ESP here is again gas lock. The graphical representation of the Ampere, TM, and Pi data depicts a periodic and continuous gas-lock removal process. When the AFR is disabled, a gas-lock develops, causing the TM to increase and therefore shutting the ESP. The AFR application successfully eliminates gas lock on the ESP pump without shutting the ESP. Using the AFR, a basic ESP systems constructed from common materials will be able to tackle challenges in problematic wells.
Follow-Up Study to Abate Carbon Emissions in Jack Up Rig Operation in East Java Area, Indonesia
Nowadays, offshore drilling operations are still rare to record the number of carbon emissions, primarily from fuel combustion. This paper provides the guideline to measure the quantity compared with production routine activities and how to abate the emission to focus on drilling activities. On the other hand, the legislative requirement might be emphasized to support the recent Glasgow Climate Pact at COP26 in November 2021 to keep the hope of limiting global temperature to 1.5˚C. Carbon emissions are analyzed based on the API Compendium of Greenhouse Gas Emission Methodologies for The Oil and Natural Gas Industry (2009). The authors provide practical equations to implement in offshore drilling activities to estimate carbon emission of CO2, N2O, and CH4 from stationary combustion of rig engines and marine vessels. SANGEA™ Software as a GreenHouse Gas (GHG) emissions calculation tool owned by the American Petroleum Institute (API), will be used to support this study. Based on actual fuel consumption data at Field X from September 2021 until June 2022, total carbon emissions from Jackup rigs and marine vessels in drilling operations were calculated at 2,404 tons CO2e/month or 27 % compared with total emissions from routine production activities at Field X at 6,522 tons CO2e/ month. This data will continually drive well engineering and operations optimization from drilling activities to abating carbon emissions. This follow-up study will be continued and expanded in other drilling activities to obtain more data sets for further analysis to boost efforts in supporting Net Zero Carbon Emission aspirations in the oil and gas industry.
Scoring Method for Polymer Screening in Chemical EOR Application
Chemical Enhanced Oil Recovery (EOR) is one of the major methods by injecting selected chemicals to implemented reservoir. Types of commonly chemical are surfactant, polymer, alkaline. These chemicals are considerably used to enhance the oil displacement and volumetric efficiency through an extensive investigation into the applicability of EOR technology. In this research, polymer screening was conducted to select the best polymer in combination with a surfactant (Surfactant – Polymer/SP) formulation. The aim of this combined technique is to find the great potential to improve the remaining oil in L field and at high temperature of 107°C. salinity of brine L field was investigated at around 20,000 ppm. There are 4 stages in this polymer screening; pre-screening, pre-scoring, continues screening, and final scoring. Pre-screening consists of rheology, filtration test, screen factor, and thermal stability. Pre-scoring was conducted based on the result of pre-screening test. Continues screening consists of injectivity test, static adsorption, and dynamic adsorption test. Final scoring was performed after the result of continues screening. The experiment shows 6 polymer which were analyzed in the first stage: P1, P2, P3, P4, P5, and P6. The rheology of 6 polymers showed the viscosity decreased as the increasing shear rate were applied. In compatibility test, P2 were observed turbid over the time period of aging. Filtration ratio value for each of 6 polymers were performed <1.2. The screen factor test was measured with relatively range of 30 – 80. However, P6 had the highest screen factor value. The result of thermal stability test presented P1 had < 5% loss of polymer viscosity during 3 months aging. The second step of pre-scoring showed P1, P2, and P4 had passed to the next stage in continues screening with the highest value of 86.75%, 72.75%, and 74.5%. Furthermore, the injectivity test presented the resistance residual factor (RRF) of P1, P2, and P4 performed high adsorption value. However, the result of dynamic adsorption test presented P1 with the lowest value of 117 µg/g. The final scoring showed P1 was performed excellent result of 95% and thus to be preferred polymer for SP formulation.
Jack Up Rig Selection for Multi-environment Offshore Drilling in East Kalimantan and Attaka
East Kalimantan and Attaka is a mature oil and gas blocks located in offshore East Kalimantan, Indonesia covering vast geographical area with vary water depth ranging from 14 feet as the shallowest and more than 1,000 feet as the deepest. The original concept of field development utilizes Tender Assisted Rig (TAD Rig) for development drilling with fixed platforms specifically designed specifically for TAD Rig operation. An initiative to utilize a Jack Up Rig (JU Rig) was taken as a smaller satellite platform was built to develop marginal reserve in deeper water depth. Pertamina Hulu Kalimantan Timur (PHKT) as current operator commenced a continuous drilling campaign started at 2020 as a future development program of the asset. With current challenging industry environment, operating two type of mobile offshore drilling unit (MODU) as previous modus operandi was not a wise option. A process was implemented to select an appropriate MODU type. The evaluation was lead to the selection of a suitable JU Rig for all platform environment in East Kalimantan and Attaka with capability for operation in wide range of water depth as the main criteria. The selection method was based on geo-hazard identification and assessment with the priority to ensure safe operation and avoid catastrophic accident, which can lead to loss off asset, personnel safety, and environmental damage. This paper describe the procedure in selecting a proper JU Rig that meet the requirement of multienvironment platform in East Kalimantan and Attaka. This initiative has been successful to provide optimization in drilling operation and cost efficiency for the company. Despite all the challenges encountered during execution, the operation was successful in safe manner without any incident.
Unlocking Unproduced Reservoirs at Existing Gravel Pack Zone Using Straddle Screen: A Success Stories and Lesson Learnt at the Handil Field, Mahakam Block, East Kalimantan, Indonesia
Handil Field is a one of field in the Mahakam block which has various types of completion. Gravel Pack Completion is a robust solution to produce shallow reservoirs while also preventing sand from the formation to come out to the wellbore. Occasionally found on gravel pack completion wells, there are several reservoirs on the same Gravel Pack Zone. Due to reservoir properties impairment, not all of these reservoirs can be treated with gravel pack. Therefore, perforation and gravel pack treatment only performed for reservoirs with the highest reserves and also with same reservoir properties. After several years, to increase the production, there is a necessity to unlock unperforated and untreated reservoirs at gravel pack zone to produce the reserves safely. Previous method to unlock these reservoirs is by performing squeeze cementing to isolate previous producing reservoirs; perforation at new reservoirs target and then performing chemical sand control (SCON). This method is considered quite complex, takes a long time; and required high costs. The Straddle Screen is an innovative screen installation, without squeeze cementing, in the hope of producing the existing gravel pack zone in a commingle with the newly opened reservoir in the same zone. Additional perforation in the existing gravel pack zone using straddle screen have been carried out in 6 new reservoirs, in 6 wells in the Handil Field. This paper has the objectives: perform a comparative analysis of operating costs between squeeze cementing versus Straddle Screen installation; and analyze the results of the implementation of the Straddle Screen in Handil Field, Mahakam Block. The procedure begins with collecting well and reservoirs data; determine the type of perforation, type of screen, the installation of the straddle screen; and ends by evaluating the results of the work. Additional perforation work in the compared to the squeeze cementing job with SCON. By the duration, the straddle screens have a duration of only 2 – 3 days, compared to squeeze cementing work with SCON which has a duration of 14 days. From a total of 6 completed works, it was found that the reservoir production succeeded in producing hydrocarbons without any sand. Carrying out direct perforation and install straddle screens has proven to be able to produce even with small stakes, which was previously uneconomical if it had to be done with cementing and SCON operations, especially in existing gravel existing gravel pack zone without squeeze cementing succeeded in opening reserves with a total of 140.000 bbls and 0.08 BCF from 6 reservoirs, and proven has cost saving up to USD 300,000 per job when pack zones.
Cased-Hole Pulsed Neutron Logging as alternative of Fluid Analysis Sampling Test in Mature Field Development
To optimize the efficiency of operation in Mahakam as a mature field, the industry must improve the cost efficiency of maturing assets as compensation of the declining production and high fixed cost. one- phase-well (OPW) is one of the propose solution to tackle the producing hydrocarbon challenging in mature field, which is a well architecture without 9-5/8" surface casing. In OPW scheme, well is drilled in one section only using a diverter, no BOP, from surface to TD. For safety reason, the conventional pressure temperature fluid analysis (PT-FA) logging, as the ultimate method to determine the potential of reservoirs, can no longer be performed in OPW. Indeed, PT-FA sampling log plays significant role in evaluation of fluid status identification. As alternative, a cased-hole Pulsed Neutron Logging (PNL) is then chosen to substitute PT-FA. It is challenging because in principal, those two logging completely have different objective and measurement. Before implemented in the next future OPW, comprehensive experiment has to carried out to convince that PT-FA logging can be displaced by PNL logging. PNL both conventional and advance, then were run in three recently drilled wells which have complete open-hole (OH) logs dataset along with fluid analysis (FA) and mudlog information. PNL is the interaction between neutron and formation, which corresponding primarily to the amount of hydrogen in the formation. In Mahakam, PNL always encounter field limited conditions such as tight formation (shally-sand typical) and fresh formation water sand. A conventional PNL for gas detection require high formation water salinity, so it is almost impossible to achieve the optimal condition. Advance PNL measure fast neutron and less dependence to salinity and provide better detail fluid identification in tight formation. This paper will discuss the risk and uncertainties of using a cased-hole PNL logging to replace PT-FA sampling data in specific condition encountered in Mahakam area.
Re-shifting Of a Single String Packer-less Electric Submersible Pump Gas Lift Hybrid to Fit the Up-todate Environment
Electrical Submersible Pump (ESP) gas lift hybrid advantages as discussed in the previous SPE papers number 128974 and number 176291 MS are now entering the end phase. Unfortunately, the information of the ESP gas lift hybrid limitation was limited; meanwhile the data is critical. Moreover, after time goes on, well properties and operation condition was changing then the ESP hybrid is no longer relevant. Re-shifting was then conducted to fit the current condition. The methods are developed based on the statistic of ESP gas lift hybrid failure and its causes. Some criteria are defined as a screening process to select which well needs to use ESP gas lift hybrid configuration. The criteria include water cut, gas injection rate when the gas lift mode is running, and oil cut off. From 2019 to 2020, about 43 ESP well service jobs implemented the criteria to decide the usage between ESP gas lift hybrid and ESP. The number of ESP gas lift hybrid is decreasing; the cost of well services is also cut by the unnecessary side pocket mandrel and gas lift valve. The average run life of ESP in the field is about 3.1 years; meanwhile, the new method is still running and counting for the run life because it has less failure probabilities. Slickline job for gas lift valve maintenance is also not necessary for the ESP configuration.
EVALUATION OF THE REALIZATION OF DEVELOPMENT WELLS IN 2021 AND 2022 AS AN EFFORT TO ACHIEVE THE VISION OF OIL AND GAS PRODUCTION OF 1 MILLION BOPD AND 12,000 MMSCFD
The year of 2021 and 2022 are quite interesting years for the national oil and gas industry, where the number of development drills being drilled is quite massive and aggressive compared to the drilling for the last 7 years and it is the basis for the number of drillings for the coming years. In 2021, 480 wells have been drilled and 444 onstream wells. Meanwhile in 2022, it has been approved 790 development wells and the potential for an additional 100 wells. This paper discusses the realization of the production achievement from development well, viewed from the perspective of achieving the initial flow rate (Qoi and Qgi). It is hoped that from the perspective, it can represent the evaluation of the effectiveness of the development well as well as the possibility of improvements in the future. Nationally, in 2021 the total Qoi realization was 90,180 BOPD of the 70,977 BOPD target meanwhile the total Qgi was 991 MMSCFD of the 957 MMSCFD target. If it is seen from the average Qoi achievement of 248 BOPD from the target of 204 BOPD per well, the average Qgi is 7 MMSCFD from the target of 6 MMSCFD / well. Sumatra and Natuna Islands are the areas with the highest number of drillings in 2021. The number of onstream wells are 276 wells with a total Qoi realization of 61,104 BOPD from the target of 39,889 BOPD, a total Qgi of 12 MMSCFD of the target 28 MMSCFD. For 2022, as of July 2022, 419 wells have been drilled and 329 onstream wells have been drilled. Realization of total Qoi of 50.621 BOPD from the target of 56,279 BOPD, total Qgi of 358 MMSCFD from the target of 352 MMSCFD. The future target is that by 2022, 890 wells can be drilled with a target number of onstream wells in 2022 is about 819 wells. In general, the higher realized wells are due to the discovery of additional upside potential layers, better hydrocarbon saturation than the prognosis, also contribution from new field development projects with very good results. Meanwhile, wells with lower realizations were caused by the realization of a more downdip structural layer, the character of the lens and changes in facies, the realization of lower hydrocarbon saturation and pressure, also operational constraints on drilling and well completion. Referring to the drilling success in 2021 and 2022, improving optimism as the efforts to increase national oil and gas production and to achieve the national oil and gas production target of 1 million BOPD and 12,000 MMSCFD in 2030. Another important effort to achieve this is the discovery from exploration drilling and implementation of the EOR program in potential fields. Certainly, commitment and good cooperation from all parties are needed to achieve the mission of the national oil and gas industry.
Artificial Intelligence (AI) Natural Language Processing (NLP) Applications For Identifying Suspended Job Root Cause
One of the characteristics of Big Data is data variety. This applied to work-over rig operations, which deliver reports to inform daily and summary rig program and activities, known as tour-report. Tour-report contains unstructured data, which requires extensive, time-consuming effort to read, digest, and extract meaningful information for further handling and analysis. The root causes of suspended jobs are critical to determine remediation strategy. In some cases, suspended jobs with severe problems are forced to be idle wells or long-term closed (LTC). Here are a few examples of suspended job causes, i.e., killing problem or high casing pressure, wellbore assembly overpull or stuck, fishing left in the wellbore, and well mechanical completion issue. This information can be taken by digesting unstructured data available in tour-report to come up with a remediation program, i.e., rework with rig capable of handling high casing pressure, fishing job, and wellbore repair. To gain insight and knowledge discovery of tour report, PT Pertamina Hulu Rokan (PHR) Heavy Oil Asset Optimization Team (HO AOT) and Integrated Optimization Decision Support Center (IODSC) are collaborating to deliver pilot of Artificial Intelligence (AI) Natural Language Processing (NLP) approach to identify suspended job root causes from idle wells (~800 wells in Heavy Oil fields) to come up with a remediation strategy, mainly in supporting the reactivation of LTC wells in the Rokan field program. This study shows the impact of fuzzy string-matching in handling data preprocessing. In this study, several algorithms are combined with the fuzzy string-matching method. Based on this study, fuzzy string-matching can improve the performance of classification by more than 100% in most all algorithms used.
Onshore Treatment of SBM Cuttings as Zero Discharge Preparation: Cost Efficiency of a Compliance Method in Offshore Mahakam
Offshore Mahakam is a mature field developed by Pertamina Hulu Mahakam. In Maintaining production going, more wells must be drilled. Consequently, a large amount of cuttings is generated, particularly SBM cuttings, which is considered hazardous waste. Hazardous waste management is regulated in Peraturan Pemerintah (PP) Republik Indonesia No. 22 tahun 2021 and Peraturan Menteri LHK no 6 tahun 20211, which stated that SBM cuttings can be discharged to the sea in designated areas with a dumping permit. Ex-situ dumping methods had been applied initially for handling SBM Cuttings in Offshore Mahakam, but the costs involved are quite large. Therefore, the Onshore Treatment method is developed to achieve cost efficiency in drilling operation, which is still in compliance with the regulation. This study examined the technical and financial viability of implementing the onshore treatment for SBM cutting in Offshore Mahakam.
Formation Evaluation and Reservoir Development Optimization by Multi-well Deconvolution Driven Multiwell Retrospective Testing (MRT)
An off-shore field in SE-Asia has high reservoir heterogeneity and consists of several highly permeable layers. The current field development challenges are to evaluate the potential for additional drilling and reveal the potential of production increase by injection optimization. Good Understanding of cross-well reservoir connectivity at the area, the shape and size of existing wells drainage area, reservoir properties distribution and cross-well pressure impacts are the key points for additional drilling projects and production enhancement. A1 reservoir in this field was at the focus of the study. This reservoir produces light oil and with the decrease in formation pressure, gas production has increased. A Multi-well Retrospective Testing (MRT) service was applied based on historical well pressure and production data to evaluate the reservoir compartmentalization, quantify well interference and drainage area. Historical data over 12 years (2007 to 2019), from an area consisting of 4 producers and 1 injector was analyzed using MRT. MRT extends the technique of single-well deconvolution to the analysis of pressure and production data to a group of wells. MRT was used to evaluate reservoir transmissibility between wells, cross-well interference, formation pressure history, productivity index dynamics and well drainage area. The deconvolved single unit-rate pressure drawdown transient recovered by multiwell deconvolution was interpreted to calculate formation properties around the pressure-tested well (self-transient response) and cross-well properties between offset wells (interference test response). This self-transient response is free of interference from dynamic boundaries of surrounding wells. Its interpretation by pressure transient analysis provided well drainage area, shape and aquifer/gas cap support for the well. Cross-well pressure transient responses revealed reservoir transmissibility between wells. MRT analysis found that all the offset wells were connected to the focus well. the reservoir transmissibility of the connected part of the formation between the wells was lower than expectations from open hole logs. MRT revealed weak pressure support from the aquifer and gas cap, that was insufficient to compensate field pressure for current throughputs. A formation pressure depletion trend was calculated resulting in gas liberation. However, the well drainage area was found to be extensive than expected. This could indicate a possible reservoir extension perhaps in the north-east direction. Further Geological and geophysical studies are required to address the uncertainties in the area. The results of the MRT study were used as inputs for numerical cross-well pressure modeling and then translated to conventional reservoir modeling language, to try to obtain a better understanding of MRT measured reservoir properties. he information from MRT study as used to optimize upcoming infill locations and other opportunities for production enhancement: well stimulation and injection increase.
A Successful Story: Improving Success Ratio up to 80% of Well Reactivation Job. Pamusian Field Case Study, Tarakan, North Kalimantan, Indonesia
Pamusian Field is located in the northern part of North Kalimantan, Zona 10, Pertamina Hulu Indonesia area, approximately 1 km Southeast from center of Tarakan City. Pamusian field is one of the top ten Fields (Kalimantan Area under Pertamina EP operation Area) based on its OOIP, 553 MMSTB with more than 1200 wells drilled since 1905 (brown field). However, this role doesn’t mean Pamusian production stands at a tremendous number of productions. Moreover, only 50 active wells contribute to Pamusian oil production. More than 1000 wells are idle even though there are bunch of oil opportunities on the idle wells. As an overall, Pamusian oil production remained constant for around 500 BOPD at 3 years back before massive reactivation delivered in 2021. At the end of 2020, aligned with the company’s goal to maximize existing Assets, the idea of production optimization was commissioned by improving the success ratio of well reactivation job in Pamusian Field. In the last 3 years, the success ratio of well reactivation jobs was not encouraging. The team focused on all aspects of optimization and reactivation practices. Field Review and Reactivation Lookback are aggressively conducted to figure out Pamusian Field problems. Lack of workover and well intervention jobs, inadequate surveillance data, and a misperception of well reactivation methods are raised as the root causes for underdeveloped fields. Another surprising fact is more than a hundred attic wells located up dip in the main closure are not active (idle), which has lower surrounding well in a good oil production performance (10-30 BOPD) BOPD with various of water cut 90%. Again, this is real opportunity! low hanging fruit to become more oil by producing those wells. An integrated and comprehensive assessment was successfully delivered. The most important outcome of this assessment is reactivation method recommendation, it’s called Locomotive (Low Cost, Massive Impact, & Innovative). Three innovations were created and delivered to conduct well reactivation jobs in the Pamusian field, there are Subsurface Data Hierarchy Development (to set subsurface confident level), Fill up Annulus Activity (to check fluid sample), and Locomotive Risk Mapping Assessment (to set priority by comparing confident & impact level) as a decision tool. These reactivation methods deliver a high confidence level of success. Resulting a dramatic rise of success ratio up to 80% (previously 30% at 3 years back) and oil gain average 150 – 200 BOPD which remained stable for several months until early 2022.
Wax Problem Management in Sucker Rod Pump Wells with Rig-less Hot Water through Annulus Method in Tanjung Field, South Kalimantan
Tanjung Field is located in South Kalimantan province and was discovered in 1898. Currently operated by PT Pertamina EP since 2004. The production wells in the Tanjung Field have various reservoir problems, including scale, wax or paraffin, sand, and depleted reservoir. Wax problem is the one that has the most dominant influence on the lost production opportunity. The average pour point of the Tanjung crude is between 39-42°C. Reservoir fluids that have paraffinic characteristics experience a decrease in pressure and temperatureduring the production process from the reservoir to the oil storage tank. This change in conditions causes the formation of wax deposits at several points such as around the perforation or pump intake holes, in the tubing, and in the well flowline. This wax deposits cause resistance to fluid flow, causing a decrease in production in sucker rod pump wells. In addition, the negative impact of this problem is that it can increase the frequency of well services job and chemical costs for well stimulation work. One of the efforts that can be done to overcome the problem of wax is the thermal method. Hot water is injected using a hot watering unit into the annular casing of sucker rod pump wells. Hot water injected with a temperature above the pour point is expected to clean the wax that forms around the perforation holes, pump intakes, downhole pumps, and tubing. During the work, the pumping unit continues to operate normally so that hot water can flow from the subsurface to the surface, and there is no loss of production time. This method is proved to reduce low production and even can provide a production gain compared to the potential of the well with minimum cost dan faster work duration.
ESP Performance Enhancement Using Multiphase Ejector to Reduce and Recover Casing Pressure as Sales Gas
The major issue of mature offshore facilities along ESP well operations, atmospheric casing venting has been performed as a quick guideline to prevent gas lock occurrence. Considered as field rule of thumb, this practice is able to optimize well production substantially by maintaining the desirable fluid level above submersible pump intake. In order to overcome both operational and environmental excellence, this paper deliver the extensive design, selection, sizing, and application of multiphase ejector to address: casing pressure reduction, ESP performance enhancement without loss flow phenomenon due to gas lock, and emission reduction by recovering casing gas as sales gas. Energy-efficient solution of multiphase ejector for ESP is developed using fluid dynamic modelling. Transient mode of “k-epsilon” approach is being applied during the computational process to accommodate fully turbulent flow phenomenon whereas occurred along mixing chamber between high pressure motive fluids attracting low pressure casing gas. The eddy viscosity formulation is used to account the transport effect of the turbulent shear stress inside multiphase ejector. Once computational fluid dynamic complete, field fabrication and workshop test is being conducted prior to field commissioning to obtain the best ejector performance. Benefit from tree cap of ESP wells, high pressure motive fluid is being used to generate vacuum effect inside ejector, attract low pressure casing gas, and displace the flow to medium pressure destination of pipeline network. In general, gas lock phenomenon occurred in several ESP well along baturaja carbonate reservoir with depth± 2500-2700ft TVDS and sand thickness ± 40ftTVD. Based on data shown in this paper, multiphase ejector is designed to attract the accumulated casing gas using heavy (18API) and viscous (35cp) motive fluid. The customized “Y-type” ejector succeded in lowering casing pressure of ESP-G6 well up to 15 psig followed by a wider ESP operability in terms of frequency, higher pump discharge, and a table motor temperature. This solution reliable to deliver an instant rate of 61 MCFD of casing gas without any further atmospheric casing venting application preventing further occurrence of gas lock phenomenon and better ESP operability shown by the intermittent flowing patterns.Success story of the “Y-type” ejector is the unique ventury entrance of motive fluid to disperse heavy fluid delivering suitable choke condition and vaccuum effect inside the mixing chamber of ejector. Therefore A stable ejector operations is important to be maintained as a assurance of the continuous vaccuum effect.
Cleanliness Correlation of Mono Ethylene Glycol (MEG) as Thermodynamic Hydrate Inhibitor to forecast Fresh Injection Period using Supervised Machine Learning
Production in the context of oil and gas can be defined as the total flow rate of hydrocarbon components with several other components such as water, CO2, H2S, and soil from production wells, then flows through a pipeline to the processing facilities. Oil and gas production can be limited by several factors, one of which is the issue of flow assurance such as gas hydrate, which can result in a loss of production opportunity (LPO) due to gas hydrate blockage. The most common hydrate formation prevention method is injecting hydrocarbon fluid with antifreeze chemicals called thermodynamic inhibitors such as mono ethylene glycol (MEG). However, dissolved solids contained in produced water may precipitate and tend to deposit in surface facilities including the Mono Ethylene Glycol Regeneration Unit (MRU). These can plug the MEG injection system and result in potential hydrate formation. This paper deals with how actual problems of plugging due to scaling or fouling on the MEG injection system can be minimized by analyzing process parameters and laboratory analysis results using supervised machine learning. The study suggests that machine learning can be used to predict the problem occurrence by observing the cleanliness level of lean MEG that correlates with some process parameters such as hydrocarbon flow rate, CO2 content, and wellhead flowing pressure. If the cleanliness level is above specification, the MEG injection system is assumed to be possible plugging, otherwise not plugging. Some supervised learning algorithms are compared to evaluate the performance of plugging possibility prediction. This result can be used to determine and optimize MRU operation, monitoring, and maintenance strategy.
A Discussion on Premium Connection Qualification for CCS/CCUS Well
This work aims to depict the different aspects that need to be considered for the evaluation of threaded OCTG connections used in CCS (Carbon Capture and Storage) projects. The paper also shows the different stages followed by the authors to develop a methodology that could be used to conduct such evaluation. Considering that the evaluation of threaded connections used in wells should take into loads, pressures and temperatures expected during injection and a less likely survival case, the authors have found two methods to physically evaluate the specimens and a numerical analysis to investigate extreme load cases. Numerical methods allow a quick simulation of the exposure to the survival loads by imposing sudden changes in temperatures and combined loads and pressures. In such a way, it is possible to understand the mechanical behavior within a define perimeter and be prepared for the physical testing. The physical evaluation, also known as Full Scale Testing, consider the two above-mentioned scenarios: injection in steady conditions and survival loads. For the steady conditions the evaluation of a connection following a test load envelope at sub-zero temperatures in the range of -25°C to -35°C covers most of the known scenarios. For the survival loads, it is necessary to demonstrate with a sudden exposure to freezing temperatures around -70°C that the connections can both maintain structural integrity and, subsequently, a sealing response under normal operation. The methodology described by the authors combining numerical analysis and full scale testing was applied in real cases. It demonstrated its suitability for the evaluation of OCTG threaded connections under the extreme low temperatures that could be seen during the operation of the well in Carbon Capture and Storage projects. Different materials were also evaluated during the preliminary stages as well as with the final procedure demonstrating its applicability to different types of materials from carbon steels to martensitic alloys. Considering that there is no standard in the industry capable of covering all the potential scenarios of the carbon storage well, the methodology presented herein can be used a starting point for future projects.
High Paraffinic-Naphthenic Oil Recovery Using Spacer-Assisted Surfactant on SP Chemical EOR Study
Abstract. Chemical Enhanced Oil Recovery (EOR) has been stated as an efficient method to recover trapped residual oil in reservoir but it has many challenges on selecting and screening the chemical. Molecular phenomena should be reviewed due to complex interaction between chemical component in the system. Surfactant chemical structure corresponds to chemical interaction and EOR performance. This study evaluated the performance of spacer-assisted surfactant on preliminary screening and coreflooding test. Native crude oil 48.9 API, native produced water 17571 ppm, 9 surfactants and HPAM polymer has been used. Gradual laboratory test has been conducted during preliminary screening consists of phase behavior test, IFT test, CMC test and thermal stability test. The best surfactant combined with polymer then tested on high pressure high temperature coreflooding to know its oil recovery. Preliminary screening exhibits spacer-assisted surfactant has better compatibility, lower IFT, and good thermal stability. The best surfactant, Surfactant SA2028, recovered 33.92% IOIP 68.16% ROIP during surfactant flooding and 47.17% IOIP 94.79% ROIP when combined with polymer injection. This study confirmed spacer-assisted surfactant is a new potential topic on EOR surfactant synthesis and formulation to get better performance.
Success Story Casing Design Optimization in Bentayan Structure
One of the structures being developed and very challenging in South Sumatra is Bentayan structure with strong water drive characteristics. This structure has been developed for more than 35 years by producing heavy oil and non-erupted oil, so most of it requires an artificial lift to produce well. Typical architecture of Bentayan well were using three casing there are 13-3/8”, 9-5/8” and 7” and drilled up to 1200 meter. So far, no optimization has been carried out on the casing design. The new optimization was carried out at the end of 2021 by trying to reduce one section casing (13-3/8”) then become two casing section which size 9-5/8” and 7”. Section casing 9-5/8” was drilled by 12-1/4” bit at shallow depth and this phase is part of the endurance test rig which is including rig up phase. The challenge in this phase is drilling without diverter up to 250 meters. It must be ensured that there is no shallow gas zone. The purpose of drilling up to 250 meter is the next phase can be drilled using BOP, not diverter. Section casing 7” then was drilled by 8-1/2” bit from spud to total depth. At this time, drilling was done using BOP with FIT calculations, kick margins and the correct MAISP for well control. Subsurface hazard analysis such as shallow gas, reservoir gas, sloughing shale must be carried out to mitigate potential hole problems. Rig operational planning must be delivered properly to all personal at the rig site. This Casing Design Optimization in the early stages was successfully applied in two wells. Dry Hole Basis were drilled faster on average 3 - 4 days, saving costs around US $ 300,000 / per well. There had been shale sloughing at a depth of 400 - 500 meter but it's solved by increasing mud weight. In general, drilling can be implemented without significant hole problems. With successful implementation of this optimization, this optimization will be applied for future will be applied to the next Bentayan wells and other structure to be drilled. This can reduce drilling cost so that drilling in Bentayan structure is more economical.
Industrialization One Phase Well Perforation in Marginal Shallow Reservoir while Maintaining Proper Well Integrity Aspect: Successful Milestone in Tunu Field, Delta Mahakam, East Kalimantan.
Delta Mahakam facing continues production decline, the marginal stake in shallow reservoir is currently considered to be produced in order to combat production decline. A break thru innovation by implementing One Phase Well (OPW) is the simplest well design in Pertamina Hulu Mahakam regards to marginal shallow reservoir stake and cost optimization. Well architecture is only consisting of cemented tubing up to surface and conductor pipe. Perforation job is considered as the most challenging ever in well design context, it can be considered as the first perforation without any surface casing existence in the well in Indonesia. The most challenging part is implementation of simple well design to be justified as dual barrier concept during completing the well which has to be mitigated by proper risk assessment. Therefore, the objective of this project is to ensure safely perforate and produce OPW wells by implementing robust and fit for purpose mitigation. The method used is by performing specific risk assessment to determine robust mitigation and thoroughly justification in order to perforate and produce OPW with respecting well integrity aspect and dual-barriers concept. Highlight mitigation such as justification conductor pipe as external envelope containment by installing annulus bleed-off line completed with pressure safety valve, ensuring good cement quality as competence barrier, detailed and robust perforation decision tree, noise log for specific well case to ensure no communication behind casing/tubing, review formation strength and shale thickness above perforation depth, initial punch reservoir zone prior fully perforated and also intensive well monitoring during initial production phase until well is considered stable. Dedicated mitigation is then socialized and discussed with operation team on site/barge to ensure proper execution. Supervisor and team on site also performing debriefing to team to ensure step by step job operation communicated and executed as per plan. The project can be performed safely, with 35 one phase wells (OPW) have been executed, industrialized and contributed instantaneous production gain more than 60 MMscfd without jeopardizing safety and well integrity aspect. The collaboration between engineering in town and operational in site thru effective communication and socialization of mitigation based on risk assessment is one of the key of successful and safely operation. All mitigation stated in risk assessment has been implemented properly. No integrity issue observed during perforation, sand treatment and production by robust mitigations. Well integrity assurance is continuously performed and monitored which also synchronized in online well integrity monitoring system.
Lesson Learned Coring Job at “P” Field using Conventional Coring Full Closure System
To ensure high recovery of core from the first coring job, a conventional coring full closure system was used. A full closure coring tool is an ideal solution, not only for soft, sandy, unconsolidated formations, but for problematic applications such as gravely, fractured, or under-gauge core that conventional spring catchers cannot handle. Full closure coring tools ensure capture and a high recovery rate with hydraulically activated which minimizes mechanical parts and increases reliability for a broad range of applications. “P” field itself has a gravely characteristic formation that gives challenges to hole cleaning, but the main target of coring is at “B” formation below gravel depths. B formation characteristic is shally-sand/sandstone and already depleted showing from surrounding wells that give another challenge to loss circulation. Prior to penetrating this sand formation, selected producers well within a radius of 200 m which produces from the corresponding layer of formation are shut in to overcome the loss circulation risk. Coring fluid also contained additional preventive LCM as a bridge agent across the depletion zone. Another lesson learned is the coring BHA cannot be used as “reamer” prior the 2 coring. Major concern was it may cause shear pin to prematurely sheared. Therefore, after directional BHA continue to the 2nd top coring depth, a hole opener was used to smoothen the wellbore and to ensure its hole cleaning. This practice proves successful to overcome the risk of shear pin rematurely sheared inside coring BHA at the top of coring depth. The original plan coring job is to be done in 2 runs which target 30 ft in each run, but in the second run, after 14 ft of coring, there is no ROP, therefore the third run is required to finish the rest of 16 ft formation. The first run was successfully done with 99.3% recovery, the second run with 65.7% recovery but the third coring is only 13.7% recovery. During the coring job, there is no loss circulation occurs.
Estimating Solution Gas-Drive Future Well Performance As A Function Of Oil Mobility Profile
Wiggins et al. pointed out the key to know a solution gas-drive performance lies in its mobility function. In predicting future inflow performance relationship of a solution gas-drive reservoir, the underlying assumption of almost all available correlations is the oil mobility profile stays the same throughout a reservoir life. However, in order to know the complete mobility profile of a reservoir, one of the parameters that has to be know is the reservoir’s saturation distribution – which it is not. This study aims to generalize oil mobility profile of solution gas-drive reservoirs to solve the issue. All cases for this study are generated using commercial reservoir simulator. By incorporating the generalized oil mobility profile into Standing’s definition of future well performance, the new method requires only a single flow data test to be able to estimate future performance and gives a more accurate estimation compared to other method that also requires a single flow data test.
Application of Fluid Contact Analysis for Well Optimization and Field Development Strategy in Kerning Field, Central Sumatera
Determination of a fluid contact in brown field is essential for production optimization and well development strategies. In the last four years, production optimization in Kerning Field has been focused to drain Charlie and Delta Reservoir intervals which characterized by very clean sand, high quality and high fluid rate with strong water drive mechanism. However, water coning phenomena occurred in the existing production intervals, thus the identification of fluid contact is very essential to seek another potential reservoir to optimize and identify sweet spot area for new well placement. This paper presents a technique to determine a fluid contact by integrating static and dynamic data such as well logs, oil allocation from fingerprint analysis, production test and completion history data. The fluid contact analysis performed for 44 active wells and eight reservoirs in end of 2020. Fluid contact interpretation indicates thick remaining oil column in Alpha and Beta that was attractive to optimize due to unproduced for more than 10 years. Eight workovers and four infill wells executed along 2021 – 2022, it resulted total 3,076 BOPD of initial production gain with 83% of success ratio. Application of this fluid contact methodology has proved strong capability to identify potential by passed oil. It can be applied to common problems of fluid contact determination in other field areas.
Application of e-ORDC as Digital Transformation to Improve Safety, Job Planning and Execution in Sumatera Light Oil Operation of Rokan Block
ORDC (Operator Routine Duty Checklist) is one of critical activity which support production optimization and securing the HES concern as safeguard process. Nowadays, the importance of ORDC data utilization is increasing, as it supports digital transformation as part of production optimization and ES compliance. e-ORDC is a new platform by using Survey123 online system. Old process, Well Checker will be collecting well data with print paper and takes a long time for data verification and difficulty in monitoring and tracking historical wells information. The new process has been improved the quality of corrective actions, effectively, reliably, paperless and prevent delay of wrong data submission. Effective to deliver 3 types of report (oil producer, injector and gas well) to x-functional teams and O&M’s stakeholder and improve the quality information regarding surface wellhead condition and operation activities within 24 hours. This paper will explain how digital transformation in the new era of oil companies is strongly influenced by the process to execution and control. As an effort to increase digitization, e-ORDC comes with an automatic idea that will greatly facilitate users/stakeholders to access data, either collecting historical data or reviewing actual conditions from wells. This paper qualitatively classifies the project on digital business transformation into three different clusters based on technological, business, and time efficiency.
Organizational Life Cycle in PT Petrogas Jatim Utama Cendana : An Exploratory Study
This paper aims to analysis the organizational life cycle in PT Petrogas Jatim Utama Cendana strating from founding, growth and maturity phase. The research method used is an exploratory qualitative method with in-depth interview with the founder of PT Petrogas Jatim Utama Cendana. The source of data consists of primary data from observation and interview. The secondary data is gathered from document and report. To validate the data, this research used source triangulation. The data analysis used is data display and conclusion. The result shows that open and professional management style in founding phase plays critical role in founding phase of transferring Participating Interest from oil and gas contractor. The growth phase indicates by the establishment of Central Processing Facility (CPF) in Banyu Urip Field and Floating Storage Off Loading (FSO) Gagak Rimang to increase oil production to 200.000 barell oil per day. The plateau in maturity phase describes the contribution to regional revenue as of December 2021 with total USD 26.621.000. The existence of Participating Interest (PI) through Government Regulation 35/2004 contributed to transfer of knowledge of oil production and especially accelerate regional revenue’s growth.
Unlocking Opportunity Kotatua Field “X-2 Sand’; Low-Quality Reservoir and Depleted Reservoir Pressure Through Waterflood
Asset Optimization South team has successfully increased oil production in Kotatua Field by initiating water injection in the “X-2” sand. The “X-2” sand has low permeability and has historically been produced commingled with the Bravo sand, which has higher permeability. The Bravo sand has been waterflooded since 1974, while the “X-2” reservoir has been pressure depleted to the point of negligible. “X-2” pressure rejuvenation started in May 2018 with conversion of 6 commingled injectors and 1 commingled producer converted become single completion and dedicated as a pilot. During the monitoring of the waterflood response, apart from BHP monitoring, the extensive oil fingerprinting analysis was accrued out to determine oil allocation and zonal contribution. After observing the waterflood response, the project was expanded in 2019 by converting 3 more injectors and workover 16 producers to single completion of “X-2’ sand. End of 2019 the project has successfully delivered incremental 2,589 BOPD equivalent to 746 MSTB cumulative with a total expenditure of US$ 1.0 MM. It delivered additional reserves 3.7 MMSTB until August 2022.
Utilization of Low Code Framework Tool for Knowledge Management in Well Service
Well service activities hold important role in maintaining production sustainability from subsurface to surface. This makes conducting well service jobs safely, efficiently, and effectively has become focus for many oil & gas companies. But in the execution phase in the field, knowledge gap among personnel often creates challenge in well service activities. Fast personnel turn over, and generation gap among personnel creates the need for strong knowledge management to ensure every personnel assigned to conduct well service execution has fully understood of the standard procedures and the best practices. This full comprehension will ensure every condition in the field will be handled with the most optimal way. Previously there is not any system available to easily access company specific (operation/area) knowledge from the field by every personnel both experienced and young green company man/ woman. To develop a strong knowledge management in the field execution, well service team deployed a well service handbook in the form of mobile application. This handbook consists of guideline for job execution as well as tool to calculate various parameter based on proprietary formula defined by subject matter expert experience. By using a mobile application, every field personnel easily access the standard guideline wherever they are in the field. This will ensure all personnel execute the job optimally regardless their years of experience. The mobile well service handbook app is developed using PowerApps low code framework. By leveraging low code application development, team can meet the urgent need of rapid deployment to field operation. Low code framework also enables team to be more agile in adjusting the application immediately based on feedback from the field. Implementation of this initiative could minimize human error related to well service job execution. Especially on sub-optimum suspended jobs, working team could assure that the optimum effort had been conducted optimally as well as suspending job safely before next well intervention job will be assigned.
Maximizing Gas Monetization through Synergy Borderless between Pertamina EP and Pertamina Hulu Sanga Sanga
PEP asset 5 should meet the contractual rate supply to PLN Tj. Batu at a minimum rate of 5 mmscfd. Nevertheless, PEP struggled to sustain production due to gas facility limitations, depending mainly on natural flow from gas wells to provide via line 39 km and minimum pressure 465 psig on PLN Tj. Batu. Gas production was not optimal based on reserve evaluation, with a recovery factor of just 36% from existing conditions. The minimum wellhead pressure must be reduced to maximize recovery from gas potential. It was initially intended to build a new compressor plant, which would drastically reduce the economics of gas monetization. On April 2021, Pertamina decided to consolidate amongst various upstream business units which operate in Kalimantan; PEP and PHSS is consolidated under Zone 9. A group team from subsurface and surface facilities representatives of PEP and PHSS analyzed various upside potentials from consolidating these two assets by pursuing synergy to accelerate produce gas potential from NKL field Pertamina EP through PHSS facilities. The study has to fulfilled several requirements from each parties PEP, PHSS and PLN. The primary method used was a borderless operation, which aligned the PEP and PHSS production systems as a single integrated system rather than several independent systems. Prior to synergy, NKL gas would flow onstream via the NKL gas plant and the existing 39 km trunkline via the Binangat line, with a minimum pressure of 465-565 psig on PLN Tj Batu. Since most NKL gas reservoirs are depletion driven, a compression system will be required. It is intended to create a new pipeline to divert the commercialization route through Lampake Station PHSS (150-200 psi), which would lower the estimated minimum wellhead pressure to 250 psig without installing a new compression system. In September 2022, NKL gas began providing 5 mmscfd to PLN Tj. Batu for three years. Borderless synergy provides cost-effective development solutions, resulting in faster monetization and much-increased income for the Sangasanga area.
Success Story of Sucker Rod Pump and Wellhead Compressor Implementation to Handle Liquid Loading Problem in Gas Well, Kampar Block, Indonesia
An accurate and easy-to-use method is highly desirable. This paper fills that gap. Starting from Turner et al (1969), Coleman et al (1991) equations for determining the critical rate as the main cause of liquid loading problem. Gas critical velocity is the minimum parameter that is required to lift liquid droplets to surface. This paper will use unusual method to carry out fluid in the wellbore using a sucker rod pump and wellhead compressor to help stabilize gas rate after the liquid loading problem solved. The author made a breakthrough using a sucker rod pump that is uncommon used in gas well to lift formation fluid from tubing pump that causes liquid loading and also increase gas velocity. When the gas velocity is increasing, the gas rate will also increase, so the gas will flow / produce through the annulus. The key success affecting this method, is how to design the appropriate tubing pump size according to liquid level and type of Sucker Rod Pump needed. In determining the design for SRP, the first thing that needs to be done is to calculate the weight of the polish rod string from the surface to the desired Pump Setting Depth. Next, we need to calculate the minimum and maximum tensile stress of the string. After that, we performed calculate the value of counterbalance from the SRP and then calculate the peak torque required. The final step is to calculate the horsepower of the electric motor needed to move the SRP, along with the right stroke per minute (SPM) and the stroke length (SL). The uncommon method that have been carried out in the gas wells of the Kampar block, are proven to be successful to handle the problem of liquid loading in gas wells with the proper pump size and sucker rod pump design. The use of SRP is also proven to be an effective method to lift produced water from wellbore. Produced water flows to surface through the tubing pump and gas flows through annulus. Wellhead compressor is also proven to be an effective way in maintaining gas rate in Gas Well to optimize its production so that the produced gas could be used as a gas feed for gas engine generator and gas fuelled heater to reduce operational cost in diesel fuel for power generation.
Subsurface and Surface Optimization Effort to Double Oil Production: A Case Study from Permata Field, Rokan Block
Permata Field is a small field that located in Rokan block, Central Sumatra Basin. Permata field discovered and produce since 1977 with current recovery factor 37%. Permata field previously only has 2 - 4 active oil producers with total oil production around 160 BOPD. To increase oil production in this mature field, several efforts conducted to tackle subsurface and surface issues. Subsurface issues consist of maintaining field reservoir pressure, existing well produce with high water cut, and inactive horizontal well already water out. While surface issue is the produced water that has reached the maximum temperature limit and the water discharge permit limit. Collaborative effort between subsurface team and surface team is needed to resolve the issues and maximize the oil production opportunity from Permata field. Reservoir management optimization program is launched to address subsurface issues by subsurface team. The optimization program includes natural dump flood review, fluid optimization strategy, and Horizontal well upside potential low quality reservoir assessment. Surface operation teams also launched Permata GS improvement effort to resolved water handling limitation issues. The effort is conducted with pit/cooling pond upgrade and installed additional 3 aerators to reduce water temperature. The collaborative effort from both teams successfully boosts oil production more than double to average ~400 BOPD.
Open Up a New Insight to Explore Bypassed Oil in Stratigraphic Flank Area Reservoir
Recognizing and further improving such stratigraphic or combination trapping conﬁgurations are important not only for future exploration portfolio but also in mature ﬁelds development, where most of the structural traps have been drilled massively in the past years. Most explorer and subsurface practitioners think that stratigraphic or combination trap has higher risk than other traps, in fact that stratigraphic traps had a commercial success rate (CSR) of 32% globally in line with other trap types (Westwood Energy, 2020). One of the ﬁeld candidates which being executed in 2021 was SLD ﬁeld that discovered in 1975 with a length of 3 kms north-south direction and 2 kms wide east-west direction. SLD ﬁeld has various productive reservoir and interestingly developed with stratigraphic trap system in Sihapas Group, this anomaly observed from current oil attribute map and proven last workover result in the ﬂank area. The reservoir target for 2021 drilling campaign was 394sd which located in ﬂank area of SLD ﬁeld. An integrated strategy has been successfully adopted in SLD ﬁeld, producing with almost ~1000 BOPD gain during 2021 drilling campaign which notably come from 394sd by stratigraphically. From structural position, 394sd is located relatively down-dip in ﬂank area while the reservoir quality change into poor quality in the up-dip position and behave as barrier or stratigraphic trap. Heterogeneity of facies changes in SLD ﬁeld impacts to the occurrence of stratigraphic trap that proved by the production attribute map from current active and last production of SLD ﬁeld which positioned in ﬂank area. One of the engineering approaches to eﬀectively producing current oil in SLD ﬁeld is narrowing well spacing and resulting a good oil production, compared back in 2010 with ~400 meters of spacing. This paper will tell in how we develop well candidacy with stratigraphic uncertainty and gained ~1000 BOPD to arrest production decline of this ﬁeld.
Experimental Studies on the Performance of Palm-Oil and Petroleum Based Surfactant in High Salinity Reservoir
The use of surfactant in tertiary oil recovery is very promising effort to mobilize the remaining oil by its ability to influence the properties of fluid and rock. Surfactants are injected to maximize the performance by lowering the interfacial tension between water and oil in the reservoir. Different types of surfactants have been evaluated and selected after series of evaluation steps. In this paper, the performance of palm-oil based surfactant (methyl ester sulfonated) in comparison to petroleum-based surfactant was investigated through screening of enhanced oil recovery (EOR) methods including interfacial tension (IFT) measurement, aqueous stability, filterability ratio (FR), thermal stability, phase behavior, dynamic adsorption, and tertiary oil recovery test. These measurements were conducted in order to make a comparative analysis determining the best surfactant in the presence of high salinity brine (~ 16,000 mg/L) and reservoir temperature at 60 °C. The findings showed both of palm-oil based and petroleum-based surfactant were compatible with the high salinity brine. Additionally, the aqueous stability of palm-oil based surfactant did not indicate a clear solution while petroleum-based surfactant presented otherwise at room temperature and at 60 °C. The IFT measurement for both palm-oil based and petroleum-based surfactant demonstrated the optimum concentration 8000 mg/L with low IFT. In the next stage of FR test results, the palm-oil based surfactant had tendency to plug porous media as the value was above 1.2 while the petroleum-based surfactant met the criteria of FR <1.2 as the value was 1.04. The results of thermal stability test, the IFT value of the palm-oil based surfactant was decreasing while petroleum-based surfactant was relatively constant. In the phase behavior test, both of surfactant formed a Winsor type III. The result of the dynamic adsorption of palm-oil based surfactant did not show the lowest-standard limit of adsorption value < 400 µg/gr, but petroleum-based surfactant presented 358 µg/g. Surfactant flooding were conducted in rock core with permeability of 63 mD. The petroleum-based surfactant demonstrated an oil recovery factor (RF) of 54.2% OOIP. This current surfactant screening test indicated that the palm-oil based surfactant was not well adapted to EOR methods. Overall, the main objective of this laboratory case study provides an evaluation of an alternative surfactant for EOR implementation in high salinity reservoir.
Fishing Job using Expandable Thru Tubing Fishing Tool to Catch Slickline Fish (Wire) inside 7” Casing (Success Story from Gas Well)
This paper presents success story about fishing 543 m of 0.125” slickline wire inside 7” casing of gas well (6.184” inside diameter). The well has completion string that consists of 4.5” tubing with minimum restriction 3.826” and Wireline Entry Guide at depth 2,305 meter. The top of fish is predicted at depth 3,068 meter. The fish was left in hole when slickline wire broken off in the middle of Pressure and Temperature Survey. Before the fish happened, the well was being planned for a perforation job. The objective of the fishing job is to ensure the well is clear from any obstruction that can put at risk that job. Therefore, the fishing tool must be designed to be able to run through 3.826” inside diameter and expand to 6.184”. The design incorporates metal fingers that can expand by slight jar actions. However, the metal fingers are flexible enough to be pulled out through restriction inside the wellbore. Fishing job included several critical activities: pre-work tubing clearance, tool-string selection catch the fish and retrieve out of hole, break up and connection surface lubricator to free the wire from x-mas tree while maintaining well pressure controlled. Braided line was used to have more strength to retrieve the fish. The procedure was carefully reviewed and executed to avoid create another fish left in the hole. At the end, 540 m of wire-fish was able to retrieve. Another 60 m was left in hole because it was no longer affect the planned workover. The fishing tool has successfully performed the intended job. The thru tubing fishing job is inexpensive and able to create economic opportunity to execute the planned workover. The proudest thing of this subject is the fishing tool is made locally by national industry which its design is derived from analytic thinking and collaboration to solve problem. This paper will be beneficial because this paper summarizes what a successful fishing job with a unique technical approach from planning until execution and will provide detail yet brief the actual fishing job for similar activities in the future.
The First Upward Swarf-less Section Mill Deployment in Asia Pacific – Save 50% Milling Duration
Several wells in South Sumatera area have experienced with well integrity problem of high sustained casing pressure in B annulus (9 5/8” – 13 3/8” casing annulus); and required restoring well integrity of the annulus during P&A work. Barriers need to be in place to restore the well integrity. To install barrier in such condition, the annulus must be accessed by means of section milling. The section mill operation will be performed on the 9-5/8” casing and regain access to 13-3/8” casing in a particular depth interval. There were 2 wells (Well X and Y) that were the subject to the section mill operation on 9-5/8” casing. Conventional Section Milling System was performed on well X; however, the Conventional System came with its own challenges such as, mechanical stuck pipe incident on well X which significantly increased the operation time, tons of metal swarf was returned at surface which increased the HSE risk greatly during clean up at surface and disposal and rate of milling penetration was limited by swarf handling. In the second well Y, 9-5/8” upward swarf-less section mill system was deployed to overcome the challenges from the first well. With its Innovative upward direction section mill using left hand motor and auger assembly, the technology eliminates all swarf to surface and gives multiple added value. Firstly, it enabled 50% less time to perform section milling. Thus, the carbon emission from the operation was significantly reduced as well. Secondly, no swarf (milled casing debris) was returned to surface. Thus, it eliminated stuck BHA tendency, risk to damage surface equipment, and reduced environmental impact. After the 9-5/8” upward swarf-less section mill had been done, operator was able to set an inflatable plug across the section-milled depth without encountering any issue, put cement column, and eliminate sustained casing pressure. 9-5/8” upward swarf-less section mill system saved 3.5 days of rig time compared to the previous section milling operation. By having this operation’s duration optimization, 4.6 tons of carbon emission was reduced. Globally, the technology had been run 4 times since 2018 and this project allowed to bring the technology the first time in Asia Pacific in 2022.
Well Accessibility Using Electricline Cleaner and Miller: Success Story of PK-Jx at Offshore Field Pertamina Hulu Mahakam
Mandatory step in preliminary well intervention is to check the accessibility to target depth. Occasionally restriction founded and well can’t be accessed to target depth. Coiled tubing operation needed to get well accessibility by eliminating sediment. PT. Pertamina Hulu Mahakam developing offshore ultra minimalist platform where coiled tubing operations can’t be performed. Hence, sediment elimination method with Electricline Cleaner and Miller unit which fit with offshore minimalist platform concept feasible to be performed in Mahakam Area. PK-Jx is one of Mahakam Minimalist Platform which facing restriction on intervention. Electricline is deployed to clean and mill services which had been provided by conveying a specially designed tool. To keep production optimized, periodic interventions should be performed to remove the sediment. Based on performance, during intervention should be combine the cleaner and miller to get the effective clean out. The sediment will be trap on the bailer above the cleaner or miller tools. This system is simple, cost-effective, safe and easy to handle. Electricline Cleaner and Miller can open well accessibility from 2030-2062 mBRT (28m) with high success ratio and get 100% well accessibility for next intervention. This method has proven having lower operation cost compare with conventional method. The method eliminates mobilization and demobilization from coil tubing operation which is equals to 4 days saving in operation cost with total cost reduction up to USD430,000 per job. This job efficiency is not affecting safety aspect proven with zero accident, and then reducing risk form High Risk to Low Risk due to the elimination of heavy lifting (especially during bad weather) and chemical usage. With success story of PK-Jx, we would like to share this method will be a part of solution with future development of offshore minimalist platform which heavy equipment for sediment cleaning and milling is not feasible.
Digitalization Application on Pump Stuck Identification Procedure an Effort to Support Pump Failure Reduction in Mature Steam Flood Field
Pump stuck and floating rod are one of the main contributors to pump failure in mature steam flood field. In total there are ~1000 pump stuck and floating rod events per year occurs in D field, resulting in an oil loss of ~200 MBO. The main cause of those issue is sand problem that triggered by degrading well bore screen liner integrity over time. One of the initiatives to overcome the problem is the pump stuck identification (PSI) procedure which is troubleshooting procedure that conducted by field operator before the well finally declared as pump stuck and scheduled for rig work. The procedure includes several steps based on historical best practices which include surface facility and well head equipment adjustment and down hole pump trouble shooting. However, in practice this PSI troubleshooting procedure was not standardized and properly recorded. This situation results in difficulties to ensure the work is carried out according to standard procedures and miss the opportunity to do lookbacks for future improvements. This situation triggered initiatives to improved success rate of PSI troubleshooting. This paper demonstrates the use of digitalization to maximize the PSI impact. Field operators required to input the results of the PSI procedure through a loader which automatically sends the information to the database where the PSI input compliance data is tracked regularly and evaluated for future improvement. In addition, several steps of the PSI procedure have been added to improve the current PSI troubleshooting procedure. This initiative has been fully started since the beginning of 2022 and is currently successful in maintaining the PSI compliance above 97% and successfully put back on production 87 pump stuck/floating rod wells correspond to 10,718 bbl. Oil loss avoidance and is expected to continue to increase in line with implementation consistency and continuous improvement procedures. This initiative can be adopted in other fields in maximizing the value of troubleshooting procedure.
Optimum Surface Roughness of Aluminum Coating to Protect Equipment from Corrosion with Arc Thermal Spray Aluminum Methods
Oil and gas production equipment, especially offshore which is often exposed to seawater vapor is susceptible to corrosion on the surface. Aluminum coating can be used to solve this problem. In this study, an Aluminum coating of 200 - 250 μm thickness is produced using arc thermal spray technology, with 95.05% aluminum wire as feedstock and a standoff distance of spraying ~300 mm to make the material corrosion-resistant. The substrate surface coarsening is done by grit blasting technique using abrasive aluminum oxide at 140-280 mm spray distance and 3-6 bar pressure. Observations were carried out in four samples with different surface roughness variations: Surface roughness of substrate about 30-50 μm, Surface roughness of substrate about 60-80 μm, Surface roughness of substrate more than 120 μm, and Surface roughness of the substrate material as it is with no blasting, about 3-27 μm. The adhesion strength of aluminum coating on the non-blasting substrate has the smallest value and fails in a series of tests. Surface roughness of 60-80 μm produces the best adhesion. The adhesion strength is influenced by the mechanical interlocking bond between the coating and the substrate. The rougher surface has a stronger interlocking bond that increases adhesiveness. However, the excessively high surface roughness reduces the bond strength. The adhesion strength of the aluminum coating increases with increasing surface roughness of the substrate to a certain degree of roughness that does not exceed 80 μm. The better the adhesion of the coating, the more protected the material will be from corrosion.
Optimizing Gas Utilization by Using Multi-destination Contract Term
The unrealized projected demand reflected on Gas Sales Agreement (“GSA”) in point-to-point delivery scheme gave potential risk of unutilized volume when the end user is unable to receive and utilize gas delivered as contracted and might trigger Take-or-Pay or advance payment for PT Perusahaan Gas Negara Tbk as seller. The multi-destination scheme mitigates the risk by providing alternative destinations to which the gas can be delivered. This results in an increase of volume of gas delivery and the advanced payment previously paid due to Take-or-Pay shall be entirely taken.
Low Salinity Water Injection North Mahakam Sangasanga Field Case Study
North Mahakam Sangasanga is one of the mature oil fields in onshore Kutai Basin, East Kalimantan. The field was discovered by NIIHM – a Dutch oil company in 1897. The field comprises over 100 hydrocarbon accumulations in deltaic sands. Hydrocarbon accumulations are found at depths as shallow as 100 mSS and continue down to 1800 mSS. Low Salinity Water injection has been performed since 2008 with an extraordinary results. The paper intends to describe the success story of this secondary recovery by low salinity water injection application in North Mahakam Sangasanga field main zone, which has successfully increased the oil recovery. The water from shallow reservoirs is produced with electrical sub-submersible pumps or sucker rod pumps and directly pumped into the water injection network connected to water injector wells with a wellhead pressure of 250 psi. The water injection rate is 300 to 2500 bwpd from 54 active water producers. The water production and injection rate evolve over time following the reservoir management practice and well-producer availability. Currently, this water injection is resulting in oil production of 1700 bopd. Monitoring and observation of the performance of water injector and oil producer wells are performed daily. Wellhead data is regularly checked and recorded. On the reservoir basis, monitoring has been done regularly by controlling the material balance of the reservoir by creating VRR so that water injection allocation and injection recommendation can be regularly updated., Some reservoirs are expected to have oil recovery up to 40%. A progressive development plan embraced this excellent result. Following the success story, an ongoing development study on the low salinity water injection application is initiated for 6 selected reservoirs in North Mahakam Sangasanga Field.
Successful Complex Thru Tubing Cementing and Sand Consolidation Operation in BL-x Mahakam, East Kalimantan, Indonesia
The Mahakam block, located in East Kalimantan, Indonesia, is operated by Pertamina HuluMahakam (PHM). Bekapai Field is one of those fields, and it has several wells that have penetrated the oil and gas reservoir. Some of them have a large oil rate and reserve, as well as good reservoir characteristics, such as high permeability and low swelling clay content. The zone must be opened due to the increased demand for oil. Sand consolidation is required due to the fact that it is an unconsolidated sandstone reservoir. BL-x case, access to the target zone was blocked by a fairly high sediment layer requiring sediment clean out/milling, and then another issue arises from the gravel pack zone, which is no longer producing and is thus cemented. There are two other unconsolidated reservoirs with cement gravel pack in the same packer zone that have good potential. It is challenging to place, and the reservoir has varying permeability, porosity, and clay content, but it is still an excellent candidate for sand consolidation treatment. On August 2021, the team successfully delivered a chain of complex operation, starting sediment milling for well accessibility, cementing using micro particulate cement to isolate zone behind gravel pack, until finishing the sand consolidation operation in the neighboring zone. The delivery added 1075 BOPD to the production stream, an excellent feat for 40-years old Bekapai field. In addition, it was carried safely amidst Covid-19 pandemic situation. This paper will elaborate on the experience of a successful complex operation that was carried out safely, as well as discuss in detail some of the measurable milestone achievements from the operation.
H Field Development: Past, Present, and Future – A Journey to Achieve New Peak Production after 35 Years of Depletion
H Field was discovered in 1975 and starting the first production in 1983. The first peak oil production was achieved in 1987 and then continued decline. In 2017, a subsurface study was conducted by re-interpretation of existing 2D-seismic data, well logs, and formation evaluation with result local attic opportunity and generate recommendation to execute drilling campaign. After 35 years of production, a drilling program consist of three infill wells were executed in 2018 and delivering a very success result by achieving a second peak oil production with incremental production 300% from existing baseline. By the success of these three infill wells, a followed-up drilling campaign consist of four infill wells was initiated and executed in 2021 which again had yielded good result to deliver the third peak production. To reduce further geological uncertainty, a 3D-seismic package will be acquisitioned in 2023 and will be used for further development infill wells. Throughout the last 5 years activity, various challenges, and uncertainties from subsurface and surface have been overcome such as 2D-seismic, structural geology, fluid contacts, deep well drilling, Low-Quality Reservoir (LQR), limited fluid flow, early water breakthrough, high reservoir temperature, high wellhead pressure, and aging flow line. This paper illustrated the chronology and lesson learned of H Field journey, from initial development to recent development, and its future development.
Well’s Liquid Production Rate Prediction Method Utilizing Temperature Profile Reverse Calculation, One Step Closer to Virtual Production Test on Limited Wellhead Data
Wellhead data and the actual production rate measurement are the most parameters evaluated to be prepared for any production dynamic by still respecting to the downstream facility limitation. One of the them is liquid production rate. Case study discussed is Tunu Field in Mahakam. Although it is a gas field, liquid rate is important information to shut in high liquid producer wells prioritization in case of limitation on the production facility (i.e liquid transfer pump break down). Production parameter is nearly blind on well level. Flowing pressure, temperature, and gas rate by orifice flowmeter are locally updated by weekly visit. While well’s liquid production rate refers to periodical collective well test from test separator or clean up history by mobile testing unit. Unfortunately, 73% from 29 test separators were unfit to measure liquid due to aging. While mobile testing units were limited and costly for routine well production test. Well’s characteristics vary depend on the open reservoir. From average 220 active wells, most of them were strong water drive on shallow reservoir and depletion drive gas or retrograde condensate with water contact in the deeper reservoir. Therefore, liquid production was inevitable on the late production phase. With the absent of updated well test data, liquid producer well identification became very challenging. In 2021, liquid estimation accuracy on field level was 50% compared to actual liquid production. At this period, it was estimated 961 MMscf production lost on recorded emergency events due to false identification or ineffective decision in shut in high liquid wells. The initiative came up with development of virtual well’s liquid production prediction. The concept is reverse calculation of temperature profile estimation on flowing fluid inside conduit. The overall heat transfer coefficient (u-value) as one of critical parameter was categorized based well’s completion type by referring to more than 1500 historical test data. It was combined with wellhead parameter and reservoir data to calculate estimated liquid. Using combination of nodal analysis software and VBA based spreadsheet, an in-house tool was developed to provide quick and consistent calculation on all of active wells. On the field level, the accuracy of liquid prediction was significantly increase to 90 – 110 % and all high liquid producers could be well identified in 15 minutes. This initiative provided a quick and adequate well’s liquid production estimation at free maintenance and operation cost to be ready at any time, one step closer to virtual well production test for wider application.
Problem Solving of Flow Assurance due to Viscosities Issue in the Oil Well Flowline of Field-X Using Surface Chemical Injection
Several wells in X Field have problems related to high pressure in the flowline due to high viscosities which are related with X-crude pour point properties. Current practice to solve the problem is by chemical stimulation to the wellbore using solvent. The chemical is proposed since it can create oil water emulsion, which hypothetically may have lower viscosity than the crude oil itself. Historically, opportunity to utilize viscosity reducing chemical agent already identified and laboratory tested in 2017 and 2018 from two company providers. The Operation Laboratory conducted rheology tests at various chemical concentrations to determine whether chemical injection will give better flowability of the crude oil. One of the recommendations from the laboratory test is to conduct a field trial to see the real effectiveness and also compatibility with field operation. Project team decided to implement a different methodology to reduce viscosity through surface chemical injection. This pilot project started with selection candidates in which congeal wells are mostly located in Area A, B, C, and D in X field. After candidates are fixed, the project team measures the oil properties (viscosity, water cut, pour point, and oil well test) for each well (before chemical injection). Parallel with candidate selection, the project team also executed a procurement process to purchase chemical and injection equipments. After preparation completes, continuous chemical injection takes place in the surface pipeline. So, the producer well is still ON while the chemical pump keeps injecting solvent chemicals. During continuous chemical injection, the project team measures the oil properties and well tests to see the impact from solvent chemicals. This pilot project took two weeks of continuous injection for each well and after that injection stopped and the project team evaluated the result. After doing surface chemical injection for 5 wells, it is concluded that chemical X gives a positive impact to oil viscosity that flows in the surface pipeline. Oil viscosity is reduced 30 – 50% after injecting solvent chemicals (4 out of 5 wells). This ultimately will increase oil production. Viscosity reductions happen effectively at 3-5 days after injection starting and higher injection rate from chemicals will result in larger viscosity reduction. Viscosity reduction result also varied by well depending on initial oil production, water cut, congeal severity, and wellhead temperature.
Integrated Fault Seal Analysis Methods For Step-OutDevelopment Wells: A Case Study; Pematang LantihField, South Sumatra Basin, Jambi-Indonesia
Fault seal analysis has been widely applied in hydrocarbon exploration and field development. In exploration, analysis of the sealing capacity of fault could assess the probability of finding hydrocarbons that involve the definition of spill point, column height, juxtaposition, and compartmentalization. In field development, fault can provide seals, baffles and/or conduits to fluid flow. Proposing a step-out development well beyond main producing area separated by major fault carries subsurface uncertainties. The amount of well and reservoir data from nearby main producing field is an advantage. However, associated risks in the new area without well penetration particularly on the fault characteristics need to be assessed. This paper elaborates the study of fault seal characteristics separating main field and new step out area. Pematang Lantih consists of several structures that are bounded by faults. Pematang Lantih field (main structure) has been developed since 2015 and infill development program has reached its effective hydrocarbon drainage radius. Subsurface evaluation of the area suggests that the structure to the southeast of the main field has a potential hydrocarbon. A step-out well was then proposed to be drilled in the southeast block. The NNE-SSW normal fault separated the southeast block from the main field. Although the southeast block is relatively at the downthrown side of the fault, seismic attribute analysis showed considerable hydrocarbon potential. The size of the fault and the magnitude of its displacement suggest that the fault might potentially act as a barrier between the main field and the southeast block. A combination of methods was performed in this study. The first method was Geomechanical study derived from various data evaluation of well-logs, drilling parameters and regional data. Field Stress model related to fault integrity and reactivation risk were resulted from this first approach. The second method applied the triangle juxtaposition diagram which represents across-fault relationship and sealing capacity from a single well. The fault’s throw and field stratigraphy were used to generate juxtaposition diagram. Membrane seals were assessed by using Shale Gouge Ratio (SGR) where shale material (vshale) was incorporated into the fault as a function of fault throw. The third method involved 3D fault model where stratigraphic juxtaposition on fault plane and seal properties derived from 3D grid model can be displayed in three dimensional. This provided a relatively more accurate view of potential leaking or sealing zone and also guided the well geometry to be drilled in the area adjacent to the fault. The study helped in understanding the fault characteristics (integrity, reactivation risk and seal capacity). As a result, this will help in the more confidence placement of the proposed step-out well location and the determination of subsurface target.
Dynamic Data and Flowing Material Balance Method to Unlock Potential in New Game Reservoir with Limited and Low-Resolution Data
A new production zone CD carbonate was discovered in the Sidayu field by exploration well S3ST. Post drill static evaluation shows the production zone has limited connected volume and low reservoir quality. However, converted S-3ST has excellent production performance. The differences between prognosis and actual production performance is the reason to re-evaluate the reservoir. New approach using dynamic data was proposed to re-estimate hydrocarbon in-place and reservoir properties. This approach is no needed for well interference activities that may take a long time, if reservoir permeability is low enough which will affect the economic value of the well, by combining rate and flowing pressure during production with no well downtime.
Attic Oil Zone Redevelopment to Improve Oil Recovery in Almost Watered-out Reservoirs
The A&B reservoir is a giant, complex, very mature carbonate reservoir undergoing waterflood. Given long history of production and waterflood, the main focus in the development philosophy of this reservoir was to maximize the oil recovery from existing wells. Many of these wells had zones with significant oil saturation behind casing, especially in the attic zone. The key to improve the recovery factor of the mature reservoir was through the redevelopment of the attic zone by shift-up and change-layer workovers. The campaign was started with a saturation logging job which was successful in locating the attic oil zone which then gave high oil rate after the zone was opened. This success was then followed by a comprehensive geological, petrophysical, and engineering review of hundreds of the existing wells. To boost the oil gain, ESP upsizing was programmed for wells with sufficiently high productivity. Several wells have been identified for the campaign. To date, seventeen jobs have been conducted successfully. Overall, the campaign could unlock the attic oil and resulted in significant oil gain. One well with saturation logging prior to the workover experienced notable watercut reduction. The production of the well with bigsize ESP was boosted four times, while the watercut was reduced rather than increased. In other wells, oil production increase was obtained while the watercut being relatively unchanged. Further evaluation is needed especially to determine the minimum attic zone thickness and minimum up-shifting distance from the existing producing intervals that would result in economical oil gain. This paper discusses the results of the past two years of the attic oil redevelopment campaign conducted in the A&B reservoir. The approach presented in this paper is applicable to mature fields at very high watercut stage.
Managing Drilling Risks in Ultra-Shallow Horizontal Well in Delta Steam Flood Field
Delta Field, a mature heavy oil Field, is one of the world's most extensive steam flood operations. The pay zones in “R” and “PK” formations range from 300 ft to 700 ft. The 172 horizontal wells, categorized as ultra-shallow horizontal and extended reach wells, had been drilled to ramp up oil production in the Delta Field since 2009. The primary drilling challenge in ultra-shallow horizontal wells is the high dogleg severity, up to 21°/100 ft, causing borehole geometry-related problems such as a tight hole, parted BHA, and casing tag. The complexity of the drilling challenges escalates with the characteristics of the formation in the Delta Field. The depleted unconsolidated sand formations caused the risk of severe lost circulation. Statistically, 46% of the drilling problems were total lost circulation cases and had caused several hole stability and stuck pipe cases. In addition, the matured steam injection to the pay zone formations adds the potential for a steam kick. As the drilling penetrates the steam pocket, the drilling mud is exposed to a temperature of up to 250°F. Steam kick ranks third in the highest occurrence of drilling problems in all drilling operations in the Delta Field. Therefore, it is crucial to develop improvements to manage these drilling risks for the next campaign. A lessons learned-based study from previous drilling campaigns was conducted to improve drilling strategy to manage those significant drilling risks in ultra-shallow horizontal wells in the Delta Field. This paper elaborates on three main improvements developed and implemented in the 2022 horizontal drilling campaign: well design and drilling program, steam injector shut-in strategy, and drilling procedure in lost circulation conditions. After implementing these improvements in nine horizontal wells, the well geometry- related problems still occurred during the drilling landing section in two wells. However, the drilling could proceed to the target depth. The lost circulation still occurred, but the implementation of the blind drilling strategy allowed the drilling to reach the target depth without further problems. Furthermore, the steam injector shut-in strategy reduced the severity of lost circulation and eliminated well control events. In the end, the average non-productive time caused by well problems decreased by 23 hours per well in 2022.
Optimization of Waste Pit Treatment Using The TAPIR Method in Tanjung Field, South Kalimantan
Pertamina EP Tanjung Field is engaged in the upstream oil and gas sector with oil and gas exploration and production activities where there is produced water that arises from these activities. The produced water is pumped to the WIP (Water Injection Plant) facility, then all produced water is injected into the well. injection as pressure maintenance (zero discharge program). The need for clean water for injection water is an average of 89,632 barrels in 2020 so that quite a lot of water is needed from the Clean Water Treatment Plant (WTP) facility owned by PEP Tanjung Field. In addition, there are fluids from outside the process of existing production facilities such as cellars, rig activities, workshops and other supporting activities that enter the fluid separation facility and then the separated water is discharged into the environment. The fluid separation activity from outside the process of the existing production facility has not been maximized so that the amount of B3 waste resulting from the separation process is quite large. One of the efforts that can be done to overcome this problem is to use the TAPIR Method (Accommodate, Sediment, Separate, Transfer) where with this method modifications are made to the fluid separation process and also the waste pit building. Discharged into the environment and can be useful in increasing the volume of water that can be injected into the injection well facility because it already uses a zero discharge system by modifying the Waste Pit facility minor. This method has proven to be effective and useful to help with the problem of injection water requirements and reduce the production waste.
Enhanced The Effectiveness Of Workover Program And Well Integrity By Combining Accoustic Ultrasound Leak Detection And Pressure Thermal Log In Depleted Mature Field South Sumatera - Indonesia
The evaluation of flow profile in the wellbore system is an important part of mature oil and gas field development. It is often complicated by life cycle of wells such as well design, completion strategy and production or injection phase. The high cost and tight economic margins require that the chosen well surveillance technique not only provides more effective workover program but also carries an acceptable risk in term of the project cost and safety. One of many well-known technologies is acoustic ultrasound leak detection and pressure thermal log. The objective of this paper is to show how a new approach of ultrasound leak detection surveillance technique combining pressure thermal log can be used to enhance the effectiveness of workover program in mature oil wells. Accoustic ultrasound data acquisition is basicly passive acoustic measurement. Various sound waves generated by fluid movement in dynamic condition will be captured by accoustic sensor. It is separated into two different frequencies : a. Ultra low frequency or narrowband spectrum (8 to 4,000 Hz), b. Wideband spectrum (8 to 60,000 Hz). High resolution of pressure temperature data surveillance is also acquired to provide a comprehensive pressure temperature behaviour in the area of interest and surrounding formation. As the result, This paper includes two case studies that demonstrate the integration of accoustic ultrasound and pressure temperature surveillance can identify undesired flow behind casing caused by well integrity problem that is not detectable with conventional method such as cement bond log and production logging tools. The first case is an artificial lift well that was challenging in data acquisition technique and operation. Another case is a gas well with high undesired water production. The data interpretation and comprehensive study provides unpredictable source of water production precisely. The source of water production was coming from non perforated zone through behind casing, squeezed zone and the casing liner. This study should be a valuable analysis to guide the remediation plan. The well production performance can be restored through proper remediation job. Moreover, this paper should be beneficial to help all engineers currently working in brown oilfield not only to identify the source of production problem precisely but also develop a comprehensive and effective workover program.
Maintain Flow Assurance & Production of ZPM Crude with Pressure Limitation of 16” MOL MMF-NGLJ
The 16” Main Oil Line (MOL) MMF-NGLJ pipeline was established in 1984, with the length of 53.54 km, and actively delivers crude oil from the ZULU, PAPA, and MIKE-MIKE (ZPM) area, with total production is 37,000 BFPD. Due to its integrity status, it is necessary to perform pressure limitation, leading to capacity reduction through the pipeline. Production optimization in the surface facility and flow assurance consideration are required to achieve the annual production target while prioritizing the safe pipeline operation. Several methods have been carried out to achieve the objective: • Maintain the flow rate through 16” MOL MMF-NGLJ to below 30,000 BFPD • Reduce the impeller size of the MIKE-MIKE MOL pump due to production declining through 16” MOL MMF-NGLJ • Routed the remaining ZPM production to 16” MOL MMF-LPRO, then commingled with production from LIMA-KLA and routed to 12” MOL LCOM-NGLB • Perform chemical (wax asphaltene dissolver) batching to prevent the clogged pipeline due to the waxy nature of crude oil With the minimum cost of surface facility optimization supported with flow assurance consideration and chemical (wax asphaltene dissolver) batching recommendation, the methods used have prevented leakage in pipeline 16” MOL MMF-NGLJ and achieved 100% of the annual production target.
Reserved Based Lending (RBL) Method for Project Financing of EGIZ Working Area
In 2020, the oil and gas industry was facing significant turbulence due to a global pandemic of coronavirus outbreak, forcing people to stay at home, industries to shut down temporarily, and global energy demand was drop dramatically, forcing oil prices to fall to lows. In that situation, oil companies must adapt so they’re doing more to cut costs. As a result of the global oil price decline, most oil and gas companies, including PT Prima Energi holding, were experiencing financial difficulty. So that funding for new projects and the acquisition of new blocks from shareholder investment and bank loans will certainly be affected. This research is about PT Prima Energi's strategy of keeping the asset and sharing that pledge with the bank. PT Prima Energi deals with a loan from a bank when the oil price was high to acquire PEG (PE PEG) assets in 2018. At that time, the cash flow of PE PEG can service this debt but after the decline in oil price, the company can’t survive although only maintain operations. PE PEG must cut many operational costs and delay expansion projects so that gives the company's cash flow performance effect not the same as when the loan agreement was signed. If PE PEG can’t repay the principal and interest of the loan, PT Prima Energi will lose its rights to PE PEG. For this reason, the company must do refinancing to settle the previous loan with the new loan. PT Prima Energi has a subsidiary named PE EGIZ that sells gas and is not affected by declining oil prices. PE EGIZ will be submitted for PE PEG loan refinancing. Because of the high-level risk business in the oil and gas industry and PE EGIZ doesn’t have assets that value bigger than the previous loan so the bank provided a new scheme of loan submission that is Reserve Based Lending (RBL). The RBL method makes the bank feel more secure because the determining loan amount uses the company’s cash flow performance and the bank will do a redetermination every 6 months to review the company’s performance. For a company like PE EGIZ that doesn’t have a big asset, it also has an advantage within process loan requests. PE EGIZ only needs to provide forecast entitlement that reflects the gas sales agreement that they have until the loan end date based on reserves tail calculation. The RBL system can help PT Prima Energi to settle the previous loan and preserve PE PEG assets.
A Laboratory Study of Surfactant Flooding Performance Using a Modified Micromodel for Chemical Enhanced Oil Recovery (cEOR) Application: Capillary Desaturation Curve (CDC)
Previous studies show that surfactant flooding in enhanced oil recovery substantially increases oil recovery due to the reduction of interfacial tension and alters the wettability of reservoir rock. The capillary desaturation curve (CDC) is often used to represent surfactant flooding performance in the laboratory study, which correlates the relationship between residual oil saturation changes and capillary number. There are many equations to define the capillary number. However, one well-known is the ratio between viscous force (fluid viscosity and injection rate) and capillary force (interfacial tension between two immiscible fluids). In this study, two surfactant commercials have been analyzed to determine the surfactant flooding performance regarding the reduction of residual oil saturation as the effect of changes in capillary number. To increase the capillary number, we modify the interfacial tension between surfactants and crude oil until reaching the ultra-low IFT region so that the capillary number can increase up to three-five orders of magnitude. Then, the reduction of residual oil saturation, which leads to increased oil production, has been analyzed during the changes in capillary number. In addition, we use a transparent modified micromodel that enables us to monitor the fluid moves in porous media lively. Advanced digital image analysis (DIA) was then used to quantify the residual oil saturation in the micromodel.The study is divided into two parts; static test (fluid-to-fluid compatibility) and dynamic test (fluid-to-rock interaction). The static test includes CMC-IFT which determine the optimum concentration to get the lowest IFT between surfactant solution and crude oil. Finally, dynamic tests for surfactant flooding have been observed using a modified micromodel to visualize the fluid displacement in the porous media. The analysis of initial oil saturation, residual oil saturation, water saturation and surfactant saturation are determined and calculated accurately using digital image analysis. The result shows that the interfacial tension between surfactant solutions and crude oil directly impacts reducing oil saturation, leading to higher oil recovery. However, the lowest IFT does not guarantee the highest oil recovery, which might not conform to the existing fundamental theory. The laboratory result shows that a particular capillary number increment is adequate for higher oil recovery. The study uses a modified micromodel that enables us to monitor the fluid moves in porous media lively. In addition, this method is quite simple and low-cost efficient but powerful, accurate, and fast compared to the conventional coreflood test. We also added quartz and cement to mimic the native core from the reservoir so that the detailed fluid-to-rock interaction can be captured in the study.
Achieving Top Performance Installation of Conductor Pipe Partition Separation System in Offshore Mahakam: Beyond the Learning Curve
Conductor Pipe Partition System (CPPS) is a system that allow drilling 2 wells from one conductor pipe. This system could bring noteworthy advantages for the development of oil and gas field by decreasing the size and/or number of platforms and to offer additional reserves access from current platform. CPPS have been utilized in Offshore Mahakam since 2005. 10 years of installation from 2005 – 2015 experience a lot of operation problem during installation due to various factor. This paper describes trouble-free technique and procedures for conductor pipe partition system installation. Misalignment, twisting CPPS, turning pipe are common problem during installation. Failed troubleshoot might result in loss of new slot for 2 wells. Conductor pipe shall be cleaned out properly to ensure smooth wall at inner part of conductor pipe with proper mud inside. Running procedure of conductor pipe partition system development involves preparation in warehouse, high competence personnel on board and also procedures in place to solve the problem when obstruction during running occurred. Since 2018 until 2022, CPPS are installed on 10 slots and 20 wells have been successfully drilled and completed. Procedure development resulted efficient learning curve from 5 days installation into 2 days installation. As a consequence, 6 million dollars of cost-saving are achieved comparing to previous procedure. With current CPPS performance, future offshore Mahakam platform will utilize CPPS in order to optimize number of slot and well can be drilled from the platform.
Successful Performance of a New Domestic Sand Consolidation Product in Mahakam
Chemical sand consolidation (SCON) as an in situ sand control method by injecting epoxy resin to re-bind and strengthen formation sand grain has been a common approach to tackle sand production issue for more than decade. Recently, a new type of SCON made by the local is being develop in Mahakam fields which offers high performance and cost effective. The newly local sand consolidation was assessed in three different wells to validate the effectiveness in both consolidation strength and regained permeability of the new product. This study will present the successful history based on performance eva ation in the treated wells. The performance evaluation of the local sand consolidation is determined through lab testing as a pre-job preparation and post treatment result including top of sediment (TOS) increment and actual recovery. Several lab testing are performed to examined the resistance of resin fluid to pressure and temperature, that consist of curing time test, compressive strength test and permeability regained test. While the assessment of TOS increment is to ensure none of formation grain are bypass the resin consolidation into the wellbore after treatment. It is concluded that the local sand consolidation is field-proven by succeeded to increase formation strength over than 1000 psi of compressive strength while keep maintaining permeability near wellbore regained up to 90%. It was found only minimum of TOS increment at maximum rate 0.26 m/day. By using local resin-based sand consolidation, all treated wells able to produce sand free with average gas rate 2 million standard cubic feet per day (MMscfd) and recovered remaining reserve in shallow section.
Optimizing “Sleeping Reservoir” The Low-Quality Reservoir (LQR) of “BE_1” Sand at “Semangat” Field: Outstanding Performances, Further Opportunities, and Challenges
“Semangat” field is one of primary field located at Wilayah Kerja (WK) Rokan, PT. Pertamina Hulu Rokan. First oil flowed in 1972 and reached peak production in 1974 with 28,865 BO. The production wells produce multiple reservoirs with simple ESP completions. Cumulative oil production was 92.4 MMSTB with current recovery factor is ~ 54%. “Semangat” field has 4 major formations with distributed across the field. Over time, “D” and “M” Formation were the high-quality reservoirs and contributed the most oil production while “BE” and “BA” Formation where low quality reservoir with mostly produce with medium to low rates. Lookback has been conducted with resulted low quality reservoir performance showed less production contribution when comingle with high-rate reservoirs. SM#007 was chosen as pilot well to produced single “BE_1” Low Quality Reservoirs (LQR) due to latest swab still shown 21 BPH/50% (2016). Surprisingly, SM#007 delivered excellent result by 564 BFPD/23 BOPD/96% WC although located at flank area. This result was triggered to accelerate produce “BE_1” LQR Sand at attic position. SM#046 was the next pilot well to produce single “BE_1” and the result shown outstanding performance with initial production 456 BFPD/257 BOPD/44% WC. By this excellent result concluded “BE_1” was still has big opportunity to be developed. The workflow process to developed “BE_1” LQR Sands was done by conducted integrated subsurface and engineering analysis such as: high resolution stratigraphic analysis, re-calculation petrophysics, fluid contact OWC analysis, and validated with production data. The final output is to identify sweet spot to optimized “BE_1” LQR Sands. Outstanding performances was delivered by “BE_1” LQR Sands from 7 wells executed with deliver ~ 400 BOPD incremental oil, achieve > 70% success rate workover and well intervention job, and reducing fluid. Those result increasingly convincing “BE_1” LQR Sand was “sleeping reservoir” with huge oil potential. The probable estimation size of prize from “BE_1” LQR Sands reach > 1 MMBO and identify more than 10 wells could produce this big opportunity by revisit interval and add new perforation of the “BE_1” LQR Sand. By having integrated and creative deep review and analysis can provide excellent result by deliver an opportunity to unlock Low Quality Reservoirs in “BE_1” Sand. Additional data such as surveillance log (CO Log) and additional new wells can increase the technical confident level to optimize the LQR Sands.
Optimizing Artificial Lift Design using Mobile Application – PEARL Volume 3.0 As A Breakthrough Solution In Digitalization Era (Study Case PDN-281) at Limau Field, Pertamina Hulu Rokan, South Sumatra, Indonesia
As a Petroleum Engineer, we have responsibility to maintain well production performance. Designing the proper artificial lift which is suitable with well characteristic and influx performance is one of the ways. PDN-281 is one of oil production well at Limau Field using ESP. By the time, this well need well service treatment and change pump capacity. Existing available tools for designing artificial lifts have some limitations such as the access flexibility, software with license only can be accessed on office computer, and also long & complex steps for designing. Other than that, during 2020 – 2021, Indonesian Government has Work From Home Regulation which make the access to design and evaluate artificial lift is limited. By this condition, we realize that there is room for improvements in tools for designing and evaluating artificial lift. PEARL Volume 3.0 becomes a breakthrough innovation in Artificial Lift Design because we bring manual design at computer to mobile application which can be installed in the mobile phone. Other than that, this improvement is sustainable development from previous application; PEARL Volume 1.0; which is now equipped with Electric Submersible Pump & Gas Lift Design. So we can do the artificial lift design everywhere and every time. This application is built based on international standards and literatures. For designing ESP the calculation standards are referred to API RP 11S4, Kermit E. Brown – The technology of Artificial Lift Methods Volume 2b, Gabor Takacs – Electric Submersible Pump Manual Designs, Operations, and Maintenance. While for designing Gas Lift is referred to API RP V6, Kermit E. Brown – The technology of Artificial Lift Methods Volume 2A, Gabor Takacs – Gas Lift Manual. All the design steps are plotted in the Excel and then translated into Android Language using Android Studio Application. Other than that, we also design for the interface in order to make PEARL Application is user friendly. By using the PEARL Application Volume 3.0, Petroleum Engineers have easiness to do the artificial lift design anywhere and anytime. We transform manual design on the computer to mobile application with very user friendly interface. This also support oil and gas industry to adapt in 4.0 industry era. With PEARL Application, the accurate calculation result and give easiness to the user to operate it anytime and anywhere so it eliminates the late coordination problem. By implementing the ESP Design from PEARL Volume 3.0 Application, PDN – 281 has longer lifetime production. PEARL Application is an original innovation technology from PT. PERTAMINA EP Limau Field and has been implemented massively in several fields under PT. PERTAMINA EP. This application technology is supported Production Engineering Job for designing artificial lift and knowing well potential.
Reduce Cycle Time by Accelerate POP Well Pounding after MPU Job Completed using JDE Database Excelbased Monitoring
Sucker rod pump is an artificial lift method that is often used to lift heavy oil, where the lifting process from the well to the surface is using rod pump. In sucker rod pump operation, there are several pump problems that can interfere with the pump performance, one of them is fluid pounding. Fluid pounding occurs when there is not enough fluid to fill the pump barrel. When there is fluid pounding, the load borne by the SRP rod will decrease drastically because the pump capacity used exceeds the amount of fluid flowing from the reservoir to the well. Usually for safety reasons the field operator will turn off the well until the problem is resolved, turning off the well will cause an increase in oil loss. Therefore, cycle time to overcome the problem is critical. This paper proposes cycle time improvement through JDE Database Excel-based Monitoring. The improvement will ensure well will be immediately re-POP so as to reduce LPO. To identify the presence of fluid pounding, it can be seen from the shape of the dyno card that indicating a lump (load up/down) during the down stroke and there is a large pressure difference between the upstroke and down stroke (> +/- 25%). Usually, the operation team will do a daily check and when the pumping unit of a well is found vibrated, it will be declared as suspect pounding. One way to overcome the problem of fluid pounding is to reduce the stroke per minute or stroke length. When fluid pounding occurs, an exception signal will pop to engineer’s dashboard to do review the dyno card and release stroke length adjustment program. it has been identified that the delay time to put well back on production after program execution is due to lack of monitoring when the work is completed. The improvement is fully utilizing digital surveillance and information by combining exception-based signal (online dashboard) with excel based tool that connects with enterprise resource planning database system. Once the ticket is completed, the information will pop and flag the monitoring tool for follow up or reminder to put well back on production. The improvement results show that put on production cycle time data have increased from 58 hours in the 1st to 4thmonth period to 6.4 hours. Utilizing digital surveillance and operation information to improve well down cycle time by combining exception-based signal (online dashboard) with excel based tool that connects with enterprise resource planning database system.
Integrated Data Management and Digital System in Well Intervention Program Business Process. An Implementation Case Study from Mahakam Indonesia
In order to maintain the production rate in Mahakam, every year more than 4000 well intervention workloads are carried out as outlined in the Well Intervention Program. This work program goes through several stages starting from request, costing, workload determination, making program details up to approval from the engineering, operation, and economic value to ensure the work is carried out safely, efficiently and profitably. This process involves multiple entities and also multi-layer approval. This paper will explain the utilization of data management applications and digital systems in the Mahakam Well Intervention Business process and the various benefits provided. A system was developed to assist the process of creating, implementing, recording and reporting well intervention workload using a web based application. This application is proven to provide enormous benefits in well intervention activities in Mahakam. Shorten the program creation time so that the entire process, which initially took 3 days, can be completed in less than 1 day. Increase the speed and accuracy of statistical operation calculations, more objective and measurable HSE Performance assessment to help provide early warnings of potential incidents, facilitate control and monitoring of budgets and contract expenditures as the basis of calculation cost efficiency, and facilitate the creation of external reports with valid data.
The Application of Surveillance on Gas Wells to Prevent Shortfall in Zona 13 Donggi-Matindok Field
Gas well production is governed by Gas Sales Agreement (GSA) which is consist of 3 main parts, i.e.: volume, duration, and price of the gas. If seller fail to fulfil all clause stated on the GSA, several punishments will be conducted. One of the clauses related to gas sales volume, in which if gas delivered to the buyer for 1 year is less than the amount stated in GSA, buyer need only pay for 75% gas price for the next year. Several surveillances need to be done to prevent it. Modified Isochronal Test (MIT) is an enhancement of isochronal test. This method proven more feasible to be done because we don’t need to wait for reservoir pressure reach the initial to proceed to the next choke step. We change the phase of produce-shut in wells process several times. By giving disturbance in the wells, we could see pressure change in which the data could be used to approach permeability value, skin, absolute open flow (AOF), and the estimation of reservoir boundary. All those data then used to approximate deliverability of the wells. MIT, conducted in 2019, indicated that damage value smaller than the last measurement (2018). we can see from the derivative pressure plot that boundary is not existing. Overall measurement indicated that optimistically Donggi can supply the amount of gas volume stated in GSA. This conclusion is corresponding with the production of Donggi-Matindok still stable until now. Pressure drop is also relatively small since initial production (± 300 Psi). MIT is reliable and feasible tools to see deliverability of gas wells. Meanwhile, we also need to see the condition of reservoir horoughly. First, we need to see the movement of Gas-Water Contact (GWC). We use Reservoir Monitoring Tool (RMT) to compare the result with RMT at initial condition (during open-hole period). Second, we use Pressure Build Up (PBU) to get more information about reservoir boundary condition. PBU provide a description of reservoir condition several feet from the wellbore by interpreting pressure behavior. This test covers more range than RMT. And the last data is generated from Mobile Test Unit (MTU). This is typical test unit but conducted near the wellhead to get more accurate data than measuring in Central Processing Plant (CPP). By combining those four data, we can get an approximation of gas-rate range to be produced and get a stable gas well performance to supply buyer’s demand based on GSA. We live in a paradigm, that oil and gas industry is only focused in producing oil. We should change this paradigm because gas production also gives promising profit. Efforts to develop gas well should be done in the same pace as we develop oil well.
Unlocking New Potential From Weathered Basement Reservoir at South Sumatra Basin, Study Case Jabung Block and Pertamina Aset 2 Area
Nowadays, the hydrocarbon potential of the reservoir basement is focused on the fracture zone. If there are no massive fault and fracture zone at the basement, it is believed that the basement reservoir has no hydrocarbon potential. Based on the evaluation and successful of the perforation program in the Jabung Block and Pertamina Asset 2 Area, a new understanding and opportunity was obtained in unlocking the potential in the weathered basement. Referring to this success, it is understood that a weathered basement reservoir can be a good reservoir even though it does not have an intensive natural fracture. Analysis has been done using well log data and petrophysical evaluation for the characteristics of weathered basement zone. Also refer to successful fracturing program and production for this potential reservoir. The research area has a basement of granite and granodiorite. The weathered zone is characterized by high gamma ray and resistivity, which is as fresh basement zone, but the density value is lower than the fresh basement zone. In the previous method, the weathered basement reservoir was considered to be a basement part and did not have an intensive fracture. DST results from several wells obtained a small rate, than it was decided not to continue producing from basement and moved to the deltaic reservoir that has better reservoir property and more than 200 wells have been drilled to produce the deltaic zone. There are only a dozen wells that have log data up to a weathered basement. Based on the new concept, weathered basement can be separated from fresh basement. The weathered basement has better matrix property than fresh basement. In Jabung Block, it was decided to try hydraulic fracturing at this zone. The result of fracturing at INA-1 well in 2018 obtained gas rate of 3 MMSCFD, which is significantly increased compared with previous conventional perforation 0.6 MMSCFD gas rate. Through flow channel fracturing on oil well INA-2 and INA-3 in 2018 at the neighbor structure, gives oil rate 146 BOPD and 300 BOPD, respectively. Following those results, more detailed evaluation of electric logs, mud logs, and seismic attributes using AVO have been done to know hydrocarbon potential in weathered basement. In the Pertamina Asset 2 area, in one of the fields, there are 10 wells that penetrate the weathered basement zone. Perforation efforts have been made on 3 wells in 2004 & 2011 but only get a low flow rate of 0.3 - 1 BOPD. A more detailed evaluation of the potential and completion methods include technology that could be implemented to produce a more massive weathered basement is still being carried out. It is believed that this reservoir potential also occurred at other structures in South Sumatera Basin and the other Basins in Indonesia.
Delivering Strong Production Performance through Workover Wellservice Materials Management Integration and Digitalization in PT. Pertamina Hulu Rokan - WK Rokan
Behind the strong production performance in Pertamina Hulu Rokan WK Rokan, there is one element that holds crucial role to ensure oil gain opportunities are executed as per plan, which is Workover Wellservice (WOWS) materials. Managing WK Rokan WOWS materials is a complex system, in which relies responsibility to control more than 500 types of materials and accountability to prevent risk of shortage and excess from happening. This publication elaborates successful effort done in WK Rokan to improve materials planning and optimization through integrated materials management in a single enhanced system. There were two major issues in WOWS materials management process in WK Rokan: (1) No integration in materials planning and monitoring process between stakeholder teams; (2) Minimum and manual system available for autonomous and proactive monitoring. WOWS materials inventory was managed by Drilling and Completion (D&C) team with minimum collaboration with Asset Development (AD) function. During this period, materials planning was assessed purely based on historical data, while future business plan and campaign plans were not fully considered. This resulted to lower material forecast reliability and high risk of discrepancy between material supply and demand. Now, the system has been improved by integrating material management efforts from separated teams into one cross functional material system. In the new system, accountability for WOWS materials is shared between D&C, AD and Procurement teams. Through this process improvement, the team has more control to handle risks regarding material supply and demand. The new system also offers opportunity for Material Management Digitalization (MMD). Digitalization long term objective behind MMD is to have online system, with single click can retrieve information of current inventory level, historical actual usage, and forecast moving forward. MMD in WK Rokan has been deployed through several applications, such as e-MUP (e-Materials Utilization Plan) Tool, Warehouse Availability Tool, and Artificial Lift Readyline Online Monitoring. This improvement allows user to access and retrieve data efficiently with less manual steps, reduce homeless data and reduce risk of collecting wrong data due to human error. The initiative was deployed since April 2019 under 2 stages. Stage-1 improvement (in 2019-2020) was successful to reduce deferred oil production due to materials availability by 43% and consume slow-moving materials by $ 3.0 M. Stage-2 improvement (in 2020-2021) was successful to reduce deferred oil production by 37% and consume slow-moving materials by $ 4.5 M.
Forecasting the Cost of Surface Facilities Based on Crude Oil Prices Using Linear Regression Method
In early 2016, oil prices fell to its lowest level (30.32 US/bbl) over the last 12 years, and the coronavirus (Covid-19) outbreak that started at the end of 2019 has had a negative impact on the world economy (including the oil and gas industry). Since then, petroleum exploration and exploitation activities have decreased worldwide. The oil and gas companies had to make extra cost savings and produce new strategies to avoid negative cash flow and keep the projects economically acceptable, such as: cost efficiency, proposed incentives (investment credit, interest cost recovery, etc.), proposed changes to the terms and conditions of the existing contract (depreciation acceleration, DMO holiday, share of First Tranche Petroleum (FTP), change of Split Ratio, etc.), etc. In terms of Investment Cost, this paper will assist the Contractors and the Government in determining the investment costs (surface facilities) of oil projects and its relationship to oil prices in order to assist them in evaluating the economics of oil and gas projects. Therefore, this paper will evaluate and analyze the relationship between the project cost of surface facilities (US$/bbl) and the oil price (US$/bbl). The steps had taken in this paper are as follows: collecting the project cost of surface facilities (2003–2020), oil price history (2003–2020), calculating the deviation between the cost of surface facilities and oil prices and developing a formula in the form of an estimate of the project cost of surface facilities at a certain oil price based on statistical data of 224 onshore – oil projects in Indonesia. Based on the evaluation and statistical analysis of 224 onshore – oil projects in Indonesia, the formula that shows the correlation between the project cost of surface facilities (US$/bbl) and oil price (US$/bbl) is z = 0.007x + 2.1148, where z = cost of surface facilities and x = oil price. By using the oil price year 2020 (average WTI Crude by 39 US$/bbl), the estimated cost of surface facilities in the onshore area in Indonesia is 2.38 US$/bbl.
Web-Based Application for Calculation of Physical Properties of Hydrocarbon Fluids Using Compositional Approach
The objective of this study is to develop a web-based application that can be used to generate phase diagram and calculate the physical properties of hydrocarbon fluids using a compositional approach. This study applies a combined calculation of critical temperature and pressure, bubble point pressure, dew point pressure, and dew point temperature to generate phase diagram. Calculation of critical temperature is carried out using the Chueh and Prausnitz equations, while the calculation of bubble point pressure, dew point pressure, and dew point temperature is carried out using the Newton-Rapshon method. Calculation of the physical properties of hydrocarbon fluids using a compositional approach includes parameters apparent molecular weight, compressibility factor, density, specific gravity, and viscosity for gas and liquid phases. The calculation of the compressibility factor uses the Equation of State (EOS). There are 2 choices of EOS correlation, namely Peng-Robinson and Soave-Reidlich-Kwong. Flash calculation using Newton-Rapshon method. Based on the results of the flash calculation, the physical properties of the hydrocarbon fluids for each of the above phases are calculated. The calculation of the viscosity of the gas phase uses the LeeGonzales-Eakin correlation, while the calculation of the viscosity of the liquid phase uses the LohrenzBray-Clark correlation. The both model of generates phase diagram and calculation of the physical properties of the hydrocarbon fluids is then implemented into a web-based application using the Dash Plotly framework. Dash plotly includes 3 components, namely the main programming language using Python3, a framework for building interfaces using ReactJS, and a framework for the backend using Flask. Testing results by using a set of hydrocarbon fluid data show the model can be used to predict volumetric properties and associated phase diagram as well as physical properties such as compressibility factor, density, specific gravity, and viscosity of gas and liquid phase of the fluid. Comparison with desktop version software results show that the model gives good results.
Advance ESP Failure Detection by Fuzzy Logic
Electric Submersible Pump (ESP) is the most widely used artificial lift (AL) equipment across Sumatera Light Operation (SLO). At a time, ESP experiences failures due to different causes which impact its efficiency. ESP early pump-failure detection is a crucial step to minimize LPO. In the current fluctuating or even low oil price environment, executing the wells with pump efficiency issues becomes one of the economic jobs to optimize the production level. Challenges for this option are: how fast petroleum engineer can detect early pump failure symptoms? How many resources will be allocated for the daily review of a total 2,480 producers in SLO? The previous ESP failure detection tool has been established based on manual data feeding and hard cut-off criteria to generate an “exception signal”. Unfortunately, there were many ESPs which have longer ESP failure detection time that continuously sliding. In several cases, the wells are already down due to late being captured as pump failure. There is an opportunity to develop a more realtime/online data processing and analysis using artificial intelligence (AI) approach. This project has been developed with a more robust and more parameter integration, such as fluid test data, ampere data, fluid level, wellhead pressure and other supporting data, like job history. Fuzzy logic is implemented to assess the degree of potential pump failure. Online surveillance from SCADA is utilized to improve the data quantity and data quality on the fuzzy logic tool to be more like petroleum engineers for decision-making in ESP failure detection. The result of this project is presented as Fuzzy Confidence Index (FCI), in which the highest value of FCI correspondents to a higher potential of pump failure. ESP early failure detection output is broadcasted daily through “Integrated Exception Management Signals” (IEMS), providing daily potential pump failure wells to petroleum engineers for further process.
Material Selection Analysis for Well Design Candidate for CCS/CCUS Project
As the world in ambition to limit the increment of global temperature not reaching as high as 1.5˚C, Production and consumption of oil and gas currently account for over half of global greenhouse gas emissions associated with energy use. Carbon sequestration is one of crucial element of clean energy transition since this technology contributes to both directly reducing emissions in high energy intensity economic sectors and removing CO2 to balance emissions that cannot be avoided. Making the opportunity of Indonesia’s G20 Chairmanship, PERTAMINA leads the opportunity to establish the carbon sequestration project in nation. With the spirit of synergy and collaboration with partners, technical aspect and technologies are being studied and simulated in order to help decision makers to decide appropriate action and affordability of carbon sequestration project. It is important to understand not only the subsurface structure of the field itself but well integrity to ensure that CO2 will able to inject and stays underneath for the intended period of storage take a critical consideration not only in safety but cost parameter. Material including casing, tubing and or other tubular goods points on how will the well last. This paper will using case study method by analyzing and mitigating corrosion of well material. As corrosion as material may degrade with time depending on the downhole temperature, pressure, stress conditions, and formation fluids. CO2 is very corrosive when it encounters aqueous environment and driven by high pressure, temprature, flow rate, and pH, will react with cement and steel resulting in carbonation which can lead to steel rusting. In addition to rusting, it has possibilities to form cracks on well structure and cause the leakage of CO2. In consequence, several factors had to be considered, including the choice of material. Selection of wellbore material play an important role in reducing the risk of corrosion. Strarting with the evaluation of corrosion causes (from partial pressure of CO2), low life cycle cost, design (including impact of water’s and gasses’ like SOx, NOx, O2, and H2S appearance), availability, mechanical and physical properties of material. The results of this study are well design and materials that should have been used, based on the case study that had been done. By utilizing ferrous or non ferrous metal, and selection of composite and polymer are alternatives to decrease the possibilities of corrosion. Additionally, corrosion caused by the presence of sulphur gasses can be avoided by using a protective layer like iron sulphide film. Regardless of the wellbore material, well needs to be on steady state condition in order to maintain well and CO2 condition.
Preparation and Optimalization Nano Silica Base Nanofluid Effect in Wettability For Enhanced Oil Recovery
This study focused on observing the effect of nano silica base nanofluid to change contact angle value on preparation to use for enhanced oil recovery (EOR). Nano Silica is known for its effectiveness on surfactant and easily synthesized and have lower cost production. The biggest problem in using nano silica for application on EOR process is figuring out how much is the proper amount that can be applied to give the best result. In this study, we use three concentration variation of nano silica base nano fluid and then compare them with salt water as base fluid to observe the impact reaction to EOR effectiveness by first testing its wettability measurement. For size measurement using PSA, the result shown for 0.01; 0.05; and 0.1 % variation in sequence is giving 330.8 nm, 326.1 nm and 341.4 nm respectively. For the wettability test, measurements that were completed within three days was giving contact angles of 56.31 ̊; 60.49 ̊; 62.01 ̊ sequence for base fluid, 20.39 ̊; 24.67 ̊; 27.21 ̊ sequence for concentration 0,1% nano fluid, 22.47 ̊; 28.35 ̊; 28.88 ̊ sequence for concentration 0.05% nano fluid, and 50.67 ̊; 54.66 ̊; 56.31 ̊ sequence for concentration 0.01% nano fluid. The result is shown, when higher concentration of nano fluid applied, it produces lower wettability and giving good potential to use for EOR.
Bull Heading Method without Heavy Well Intervention for Annulus Cementing to Create Well Barrier prior to Shallow Zone Perforation in Mahakam Fields
In order to maintain level of production on mature field of Mahakam, some shallow reservoirs are targeted to be produced from existing old wells. However, since the old wells were originally designed to produce reservoirs from deeper zone, there was not enough well barrier to perforate the targeted reservoirs on shallow depth. Annulus cementing is needed to create well barrier prior to shallow zone perforation. One of the challenge is marginal stakes of the reservoir which limit amount of budget that can be spend for the well intervention. Therefore, annulus cementing by bull heading method without heavy well intervention was selected. Bull heading annulus cementing method was performed to place cement column at designated depth by pumping cement from annulus-A and circulate liquid through tubing with some specific detailed procedure, i.e.: pump with high rate to minimize free fall of cement to create good cement quality, avoid cement entering the tubing by detailed cement placement and apply back pressure on the tubing to avoid u-tube effect. Avoiding cement to enter tubing is required to ensure no additional well intervention work needed to clear access in the tubing after cementing. The method has been successfully implemented on 3 wells so far. From operational point of view, this method is considered safer compare to other cementing method (no heavy lifting equipment needed), faster, more cost efficient and also proven to be able to create good cement quality as well barrier in the annulus.
Open Cell Matrix Polymer Filter as ‘Fit for Purpose’ Alternative of Thru Tubing Sand Consolidation
There are three main challenges on sand control with mechanical screen namely erosion, pass-through, and plugging. Pass-through and plugging are common issues related to the particle size distribution (PSD); meanwhile, erosion is caused by the high production rate. So far, there is no established screen that could tackle sand issues related to the PSD dependencies. This paper is aimed to present an OCMP filter as an alternative screen to tackle pass-through and plugging challenges due to improper screen slot opening size and high uniformity coefficient (UC). Conventional sand screen requires natural sand packing (NSP) to create an effective sand filter and optimal flow. Thus, it depends on the screen slot opening size to provide a good NSP. On the other hand, the data for defining slot opening size is not readily available for every reservoir. NSP is limited to the PSD of sand with a high UC and high fines. An open cell matrix polymer (OCMP) filter was introduced to solve this problem. OCMP filter was designed to allow combinations of multiple distinct layers with a range of pore sizes ranging from 180 – 565 microns. Hence, it could be an answer to the PSD-dependent screen selection. OCMP filter was conveyed by slickline and run compressed within the sleeve to allow passage through tight restrictions which then decompressed to be conformant with a significantly large inner diameter (ID) of the area requiring sand control when the sleeve is removed. OCMP filters had been successfully installed in three (3) Mahakam wells using slickline and an LCT barge. It can produce up to 600 bopd and 2.6 mmscfd of gas. In terms of production parameters, an OCMP can compete with the established Sand Consolidation in its first installations, and has a high potential to outperform most of the developed sand control technologies in Mahakam Field.
Non-Linear Formation Temperature Profile in Mahakam Fields
Formation temperature data is commonly calculated by linear interpolation data anchored by bottom hole temperature (normally from LWD tool). LWD temperature is affected by wellbore dynamic such as mud circulation. Surface temperature which used in interpolation is usually over simplified by using fixed value for all field. The method of linear interpolation itself is also not always proper, because formation temperature is not always linear. The surface temperature is varied by location, land and river has lower temperature than sea surface. The formation temperature measurement which likely not affected by wellbore dynamic are coming from stationary measurement such as wireline pressure test and fluid analysis (PT/FA) and drill stem test (DST). Formation temperature profile of Mahakam field is non-linear; the formula can be derived by using polynomial regression. It seems that the non-linearity of temperature profile in Mahakam is mainly caused by lithology (Net to Gross ratio) rather than porosity (and fluid). Sands are having a very high thermal conductivity value. The effect of overpressure is look like less to temperature which probably due to well consolidated rocks close to and along overpressure interval. This paper details the non-linear temperature profile in Mahakam fields, East Kalimantan, and further provides a technique to derive proper formation temperature profile formula which can be applied in other areas outside Mahakam.
Flow Assurance Improvement by Injecting Pour Point Depressant Chemical to Heavy Oil Well in South Mahakam Field
South Mahakam (SMK) as an offshore field had many challenges to produce and transfer hydrocarbon by underwater pipelines. One of the challenges was the wax formation due to declining temperature in the oil production system. The production was restricted by a heavy oil well withAPI 28.6º and pour point (PP) 29ºC. The oil was thickened at arrival point of a 10 inches-6.5 km underwater pipeline. It was suspected that the paraffin content was crystallized as wax around seabed sections with lowest temperature was 24ºC. Therefore, the wax deposit should be avoided by modifying the fluid handling system. Due to the unavailability of heating process and limited dilution with additional hot liquids, the pour point depressant (PPD) injection could be one of the alternative solutions. In principle, the chemical injection should be adjusted with flowing temperature is above wax appearance temperature (WAT). Therefore, the objective of this project was to study the application of PPD in SMK for solving the flow assurance issue. Methodology: There were four main steps in the study methodology. First, the representative samples were collected at well flow line and manifold during stable condition (by monitoring flow & pressure indicators). Second, laboratory test was performed, included WAT analysis by WAT 70Xi analyzer and PP measurement by ASTM D97, to support PPD lab performance test with target PP temperature was <24ºC. Third, the PPD field trial monitored actual PP during baseline period (without PPD injection) and treatment period (with PPD injection) at each end-point pipeline sections during heavy oil stable flow. Finally, the PPD optimum dosage was determined by considering the PP value at downstream section was maintained below target temperature. Result: Based on lab test result, the WAT of well effluent was 42.9ºC and PP was 29ºC. PPD performance test showed that 1 out of 2 tested products could modify PP to 20ºC with minimum dosage of 100 ppm. The selected injection point for PPD was at wellhead considering that it has higher temperature (80ºC) than oil WAT and the chemical would be well-agitated along the pipeline. After performing 7 days of field trial, the SMK flow assurance was improved by injecting 60-100 ppm of PPD chemical continuously with the actual PP at departure point (SMK manifold) was 29ºC (similar with oil PP) and at arrival point (receiving facility) was 5ºC (below oil PP), resulting more than 1,000 bpd production without wax formation issue. Conclusion: SMK heavy oil flow assurance could be unlocked by PPD injection. The chemical operation should be continuously assessed based on actual production network that might have different target temperature and feasibility of dilution with other hot liquid. Therefore, the PPD injection could be optimized and wax issue could be controlled.
Production Optimization on High GLR ESP Well Using Combination of Surface Annular Gas Separation and Feedback Mode System – Case Study B-20X
Installing ESP in high GLR wells can be tricky. The objective of gaining more liquid production on the surface can be hindered by high gas interference problems. The large amount of free gas ingested into the pump must be mitigated to make sure the pump operates at an optimum condition, hence sustaining the liquid production and prolonging the runlife of the ESP. Several high GLR wells have been producing using ESP in Bunyu Field, with some of them facing gas interference problem. The common approach to mitigate this problem is by flaring annular gas and applying VSD logic (Intake Pressure or Ampere Feedback Mode) at a certain value. However, there was special case for some wells with very high GLR and low productivity index in Bunyu Field. The annular gas could not be flared due to frequent liquid carryover from the annulus and applying feedback mode alone could not solve this issue. Further effort and trial were made at well B-20X by installing a surface separation equipment to separate the annular gas from liquid before entering the flare line. With this additional equipment, the annular gas was flared safely and liquid carryover from the annulus could be collected into a tank-on-site. Shortly after the installation of surface separation equipment combined with pump intake pressure (PIP) feedback mode, the downhole parameters (PIP, Motor Current, and Motor Load) stabilized. The resulting liquid production from the well test was also increasing and becoming more stable.
Data Analytics Applications in Oil and Gas Industry in Indonesia: Some Implementation in SKK Migas and Pertamina Hulu Rokan (PHR)
The application of data analytics becomes a growing trend in the Oil and Gas Industry. The implementation of digital transformation relying on Artificial Intelligence and Data Science such as Machine Learning, etc. is increasingly being found in various sectors in the upstream oil and gas industry and is even expected to contribute more portion in the future. In Indonesia, where upstream oil and gas industry still gives significant contribution to the country income, the growing trend of the data analytics drives the business process improvement by transforming the conventional approaches into new ways based on data sciences in order to raise effectiveness and efficiency. As one of the strategic institutions, which is responsible for managing the upstream oil and gas industry in Indonesia, SKK Migas has succeeded in developing an Integrated Operation Center (IOC), which integrates monitoring systems of Production Sharing Contract (PSC) Operators data all over Indonesia. Not only carrying out the monitoring function, the IOC has also a role as collaborative support to encourage the development of digital transformation in SKK Migas and PSC Operators towards a center of operational excellence. In carrying out its mission, SKK Migas cooperates with all PSC operators in Indonesia to gradually modernize the automation technology, build integrated dashboards and systems as well as encourage the data analytics into real program implementation that can create value and improve business process. This paper summarizes the digital innovation based on data analytics applications developed in the upstream oil and gas industry in Indonesia, which concentrates on a pilot project in SKK Migas and several application summaries of Pertamina Hulu Rokan (PHR). Derived from the IOC roadmap which places the data analytics as ultimate objective of the future development, an Oil Production & Lifting Data Analytics System which involves the data science as a prediction tool is built in order to realize the vision into reality. The system has successfully unified the puzzles of the lifting operational data which simplifies the evaluation and analysis into dashboards to speed up the decision making process. The next cases describe some data science applications developed by Pertamina Hulu Rokan (formerly Chevron Pacific Indonesia) starting from building Integrated Optimisation Decision Support Center (IODSC) as data science center of expertise. It consists of some applications involving data analytics like Integrated and Real-Time Prediction and Prevention Tool to Prevent Oil Congealing and Production Loss, that has been successfully reducing the congeal issue in Rokan block. Likewise with other application using Artificial Intelligence approach, it has been successfully developed to automate the classification of dynamometer card for rod pump failure identification. Another application that is no less advanced is the implementation of fuzzy logic to analyze ESP performance with limited surveillance data. It succeeds to detect ESP failure symptoms using limited surveillance data.
A Review For 2021 and 2022 Production Performance from Development Drilling Perspective
SKK Migas has launched a vision for the national oil and gas industry to reach 1 million barrels of oil per day (BOPD) and 12,000 MMSCFD by 2030, which will be a sign of the revival of Indonesia's upstream oil and gas industry. One of the foundations that is important for achieving these targets is through massive, aggressive and efficient development drilling activities that will help to optimize existing production and also arresting national decline rate. This paper will describe the production achievements of development wells drilled during 2021 till August 2022. It is hoped that an overview of the effectiveness of development wells will be obtained as well as possible improvements to be made in the future. 2021 and 2022 had become important period for development drilling strategy to gain more attention and more activity in a few years ahead. On a national scale, in 2021 about 480 wells had been drilled and 444 onstream wells had been drilled. Meanwhile from Work Program and Budget (WP&B) 2022 results, it has been agreed and approved as many as 790 development wells and the potential for an additional 100 wells in one of the PSC Contractors on the island of Sumatra. The year 2022 is a new milestone in terms of the number of development wells drilled with nearly 900 number of wells to be drilled, which is the highest number of wells in the last 7 years. During 2021, the annual production contribution from development wells is 16,576 BOPD and 382 MMSCFD, where the drilling activity is able to withstand the National decline rate for oil from 10.4% per year (only monitoring existing wells and conducting well intervention) to 7% per year from 2020 to 2021. By volume, 6.05 million barrels of oil and 139 BCF of gas were produced. Until August 2022, the annual production contribution from development wells was 14,870 BOPD and 199 MMSCFD which equal to 3.61 million barrels of oil and 48 BCF of gas. The development drilling program for 2022 is ongoing and it is expected that more than 800 wells can be drilled by 2022.Looking at the results in 2021 and 2022 shows that the contribution from the development well drilling program is able to help to withstand the National decline rate for oil. The competence and successful drilling of development and production of wells certainly involves many parties. It is hoped that good cooperation will continue to achieve the realization of drilling in the future, both from the subsurface aspect, drilling operations, social aspects and licensing in order for drilling programs to be executed according to schedule and get optimal production. By all means, this is to achieve the national oil and gas industry target of 1 million BOPD and 12,000 MMSCFD by 2030.
A Decade of Developing Unconventional Resources in Middle East: A Retrospective
The requirement of tapping new hydrocarbon resources has pushed the Middle East region, which typically produces hydrocarbon in conventional ways, to develop its unconventional resources. The Middle East region started to boost its unconventional resource exploration and appraisal in 2009 targeting multiple tight gas formations and source rocks. Different approaches and concepts were applied based on the exploration data and on adopting the best practices from other regions, such as North America and Argentina. Adopting the best practices from other regions and integrating comprehensive surveillance data help to define the processes and practices for developing the unconventional resources in the Middle East region. Understanding the reservoir, hydrocarbon, and the fracability of the formation is critical during the exploration phase of the field. During this phase, a full range of log and surveillance data and subsurface analysis are required to understand the fundamental characteristics of the reservoir. Moving to the appraisal phase, additional studies focus on the drilling and completion design to select the best approach as basis of design of the field and confirmation of well productivity. Details and confirmation of field development plan are required to ramp up from the appraisal phase to the development phase to be commercially viable. Furthermore, as successful unconventional resource development is characterized by having the lowest cost of well delivery and maximum productivity, optimization of well cycle is required to ensure the economics of the project. During the more than 10 years of unconventional resource development in the Middle East region, we acquired many typical field development lessons learned that could be applied in the different unconventional resource plays. Our observations cover different aspects, from both the operator and the service company perspectives. They range from the strategy of field development organizational structure to the operation execution and third-party management throughout the exploration, appraisal, and development phases. Case studies from Middle East region will be presented for each field development phase and include completion optimization, hydraulic fracturing strategy, surveillance strategy, and operational efficiency.