bluuebunny/crossref_metadata_2025 huggingface dataset:
Field B Oil Recovery Improvement Through Autonomous Inflow Control Device (AICD), A Case Study
Authors: Ariffin Mohd Hafizi , Mansor Mohd Najmi , Marimuthu Raam , Salleh Fairus Azwardy , Wahid Ali Nurul Athirah , Guillory Ryan
Published: October 2023

In a thin oil column environment, the team needs to look for a way to monetize this oil with optimized cost and reduce the risk of unwanted fluid (gas and oil). To make matter worse, the reservoir drive mechanism is mainly gas-cap expansion with moderate aquifer support. The team has looked at several methods to delay this water breakthrough i.e., standoff from Oil Water Contact (OWC) and Gas Oil Contact (GOC), and Autonomous Inflow Control Device (AICD).

There are two AICD types considered during the preliminary design stage which are the Fluid Diode Type and Rate-Control-Production (RCP) type. The team performed a cost-benefit analysis on these two types of AICD.

AICD RCP type was selected to be the best way forward for this kind of reservoir. AICD RCP type should be able to control the horizontal drawdown thus reducing the unwanted fluid production. With this type of AICD, the viscosity contrast between oil and the unwanted fluid is important. With the viscosity contrast of 0.6 cp for oil and 0.5 cp for water, the viscosity contrast is considered low. The AICD does not work effectively to reduce water production. Thus, it is important to have a good OWC standoff to delay water production.

Coupled with the reservoir dynamic model, sensitivity analysis was performed with several cases to improve the team's understanding of the AICD impact on the oil recovery. Below are cases run to ensure the best configuration were applied for each completion. Gas Oil Ratio (GOR) impact on the oil recovery with and without AICDWater Cut impact on the oil recovery with and without AICD.OWC and GOC standoff impact on the oil recovery with and without AICDNumber of AICD joints impact on the oil recovery with and without AICD

The utilization of AICD technology is predicted to significantly improve oil recovery with the expected reserve to increase around 10-25% while delaying the unwanted fluid production.

The field has an existing Inflow Control Device (ICD) well and 2 AICD wells just completed in 2022. With this, the team may analyze the benefit of the AICD compared to ICD. In addition, to ensure good recovery from the reservoir, a mud breaker was pumped to reduce the drilling mud damage in the open-hole section. Furthermore, oil and water tracers were installed to ensure water production location on the AICD open hole section.
Innovative Approach on Maximizing Recovery and Sustaining Field Development in Sisi Nubi
Authors: Sjahbunan Putra , Handoko Bayu Setyo , Sianturi Julfree , Fatkhurroyan Bima , Jannatan Muhammad Ardhyan
Published: October 2023

Sisi and Nubi Fields are mature gas fields located in offshore Mahakam Delta, East Kalimantan Indonesia. These fields have been delivering 1.4 Tcf of gas and 33 MMstb of condensate, with total 77 development wells have been drilled and put on production until the end of 2021. By existing development scheme, the current development area is already saturated with wells, whereas most of other identified reservoirs are unreachable from existing facilities and most of them is even possibly having limited resources. This paper is intending to describe the application of innovative approach, by using data driven analytics and static-dynamic approach, in an integrated subsurface synthesis, which has successfully increased the field reserves, maximize recovery and prolonged its production life time,

Existing methodology on reservoir target identifications are mainly focused on integrated static-dynamic synthesis by using existing and new wells, through geomodelling approach and massive wells correlations. This approach would mainly focus on existing development area, gradually stepping out in full reliance on latest drilled wells data. Extending its study coverage for further development outside the wells perimeter (step-out), therefore, will only add risks and uncertainties due to lack of well control. As a consequence, further development has been slowed down waiting for static and dynamic data from available wells only.

The application of data sciences and machine analytics on seismic multi-attributes and wells data as input, provide insights on gas reservoir characterization within Sisi Nubi, expanding the coverage of gas identification outside current development perimeters. This method is called MAMA, Multi Attributes Machine Analysis. As it is able to successfully summarize the correlation between subsurface data, the subsurface synthesis, therefore, was concluded comprehensively.

North Sisi and North Nubi wells, as a continuation of field development project, have been successfully drilled in 2022 with outstanding results, especially in post drilling estimated reserves. Apart from MAMA method, there was an integrated static & dynamic approach, that has successfully lead to faster development, less risks (success ratio ~90%) and better Estimated Ultimate Recovery (EUR) predictability.

The application of data-driven analytics will surely be a revolutionary step in Mahakam or even in a wider petroleum industry. It would enable to locate any potential development area outside the current development perimeters, while giving higher possibility of success and better predictability, that in the end will significantly help any field development strategies.
The Journey Towards Effective Grievance Mechanism in Upstream
Authors: Che Arshad Afzariah Binti
Published: October 2023

The United Nations Guiding Principles on Business and Human Rights (UNGP BHR) provides a clear framework in managing the aspect of human rights for governments and business sectors. While the governments are responsible to protect the human rights, businesses must respect these human rights and ensure an adequate access to remedies for the affected stakeholders. A well-designed grievance mechanism is a pivotal element in promoting accountability and transparency, with all due respect to human rights within the Company.

This paper elaborates on the remarkable journey of PETRONAS Upstream in Malaysia, namely PETRONAS Carigali Sdn. Bhd. (PCSB) in building a robust grievance mechanism management for effective and legitimate compliance with host any authority requirements, comprehended by a unique and customized approach that others can replicate.
Holistic Approach of Inorganic Scale Inhibition Application in Extending Well Production Life
Authors: Mat Deris Nurul Asyikin Binti , Siew Caleb Jia Lih , Khoo Alan , Abd Rahim Mohd Adam Bin , Arief Saleh Fakhrul Amin Bin , Amsidom Amirul Adha Bin
Published: October 2023

Flow assurance problems such as inorganic scale formation in gas lifted wells have been common in field production lifecycle and presence of higher water production accelerates this occurrence. Production impairment is the consequence of scale formation that can be eliminated by preventive measures in scale management.

The most effective technique for mitigating downhole scale formation is through the application of scale inhibitor solution injected into the near wellbore of the formation. Chemical selection is crucial to ensure effectiveness and longevity of the treatment for it not only to be technically proven but also economically viable.

Through rigorous laboratory testing and field trials, scale inhibitor squeeze (SISQ) has been the proven solution to effectively increase the productivity and uptime in most of the gas lifted wells in Hibiscus Oil & Gas Malaysia Limited assets.

The SISQ injection dosage and duration were designed based on well production and reservoir properties, and it is injected into the wellbore via the bull heading technique. The treatment has become a routine activity and well candidates are identified through scale mapping exercise.

This paper presents the journey of SISQ implementation in Hibiscus Malaysia Limited's operating fields which includes the history of actual SISQ monitoring trends and the frequency of SISQ being optimized. The cost saving and well uptime will also be discussed in this paper.
An Optimum Cloud Based Approach to Timely and Secure After-Tax Economic Analysis and Decision Making
Authors: Meulengracht Chresten Steen , Poulsen Henrik Meidell
Published: October 2023

The requirement for computing power in economic decision making is normally underestimated. It is already recognized in the oil and gas industry that for geologic and reservoir engineering calculations parallel computing power is necessary to carry out simulations of millions of cells. This paper explores he actual requirements for parallel computing for economic analysis covering decision making at all decision gates, and the added benefits of running calculations and databases in a secure cloud solution.

Economic analysis for typical oil and gas project decisions requires extensive analysis of alternative scenarios and assumptions, and robustness evaluation such as identification of after-tax key metrics and break-even values. A specific project scenario analysis is then be added to the full analysis for exploration decisions, portfolio mergers and acquisitions (M&A) decisions or selection of optimum development scenario at front end engineering and design (FEED) stage or life-extension projects. A key challenge for economists is that other disciplines do not always recognize the complexity of the analysis involved and the time required to provide the necessary decision basis for investment in multiple-billion dollar projects. Economists need to be involved at an early stage of the work process and have access to powerful computing power provided by appropriate tools in the cloud. Economic analysis is usually the last step in a series of work steps leading up to making an investment decision by management. A framework for such tools in the cloud was developed and applied to several real-case decision gate situations, including exploration, concept select, field development including life extension/enhanced recovery projects and portfolio M&A activities. Other aspects of using this framework with respect to speed, security and user friendliness was also evaluated.

An appropriate framework for covering all requirements for timely and secure after-tax economic analysis and decision making was successfully developed and applied to several real cases. This framework allows economists to define inputs and receive results in a fast and timely manner. Traditionally the discipline of economic analysis has not been considered computer-intensive or manpower-intensive, but this paper demonstrates that cloud computing is necessary and provides significant benefits and allows economic analysis to be performed faster and more timely, and still be very secure.

This novel cloud-based approach to full and extensive economic analysis fulfills all requirements for fast, timely and secure economic decision making at all decision gates including exploration, concept select, field development incl. life extension/enhanced recovery projects and portfolio M&A activities.
Dump-Flooding Electrical Submersible Pump (ESP) Approach and Lessons Learned in Sustaining Production Cycle
Authors: Nasharudin Nirwanshah , Siew Caleb Jia Lih , Ibrahim Mohd Zulfadli , Alexander Euan , Bespalov Eugene , A’akif Fadzil Nurul Aula , Bakar Hasmizah
Published: October 2023

Water injection for pressure maintenance is common in the oil and gas field to ensure a reservoir’s energy does not drop beyond the limit which will jeopardize production over time. Most of the major oil companies utilize the produced water on surface for injection or treated seawater either as pressure support or as a sweeping catalyst to recover as much hydrocarbon possible.

Water dump-flooding is one of the less common methods of pressure maintenance as compared to surface injection. This method utilizes the shallower aquifer sand as the inflow to feed the deeper reservoir. As a mature field of water-flooding, downhole injection does fit the purpose in theory but there are many considerations which need to be addressed before embarking on this route.

Even though well intervention technology has advanced in recent years, most companies would rather keep well intervention as simple and quick to avoid increasing Operating Expenditure (OPEX) which will push further the job priority. This is due to the well's accessibility, especially for offshore settings with limited space and operating window duration, especially when weather is known to be the main showstopper. Subsurface issues such as sand migration, gas handling, reservoir souring and scaling may also contribute to the system's inefficiency, which may result in system failure. Installing an ESP especially with an inverted pump does need an extensive monitoring capability be it downhole or on surface. Lack of essential data handling will often lead to malfunction which results in an expensive operation of pulling and total workover.

The dump-flooding method was chosen as the field has an existing aquifer with no serious compatibility issues across different reservoirs. The idea was deployed considering the existing platform capability with minimum modification on surface whilst ensuring the reservoir is being supported continuously. Downhole sand control for the water source zone was necessary in the designing stage to mitigate formation failure based on its lithology that would interrupt the ESP efficiency. The supported reservoir requires constant pressure charging to sustain its production and realizing some of the future development plans.

This paper will talk through the process and challenges faced during the planning, designing, commissioning, and maintenance of the dump-flood ESP. The lessons learned are crucial to ensure the project is a success for supporting the reservoir with minimal operational obstacles during execution.
Strategic Approach Towards Technology Management and Implementation at Upstream Business
Authors: Tan Grace Ying En , Zulkifli Zuraida Wong , M. Noh Nurbalqis , Ismail Mohd Syahezat
Published: October 2023

This paper summarizes the strategic approach to support operationalization efficiency of technology implementation in PETRONAS Carigali. Technology agenda became one of PETRONAS main focus since 2016. Implementation of new technology allows for improvement in production efficiency and allows company to be competitive. With high number of technology project being introduced, an effective and efficient technology management process is required to ensure optimum resource utilization and to manage technology specific risks. As a wholly owned subsidiary of PETRONAS, PETRONAS Carigali was entrusted to reinforces the strategy for this renewing focus in technology.

Since 2018, a dedicated department had been established in PETRONAS Carigali, named Upstream Technology Management (UTM), with intention to facilitate the deployment of technology in Upstream, aligning to PETRONAS Technology Agenda. Fast forward to 2020, UTM was restructured to Technology Excellence (TEX) Unit with the main focus of ensuring compliance to proper process, governance and to support the operationalization efficiency of overall PETRONAS Carigali Technology. At presence, the implementation of technology at PETRONAS Carigali is guided by several frameworks, in which the two main documents are PETRONAS Technology Management System (PTMS) and Upstream Project Management Standard (UPMS). TEX monitors two categories of technologies: in-house produced and off-the-shelf, and they are overseen by two technical approval sittings: Technology Readiness Level Committee (TRLC) and Proprietary License Technology Assessment (PLTA). Technology Readiness Levels (TRL) are a concept used to gauge a technology's level of maturity. According to the projects' progress and the technical standards established, each technology is assessed against a set of criteria before being given a TRL rating. At the same time, risk assessments are conducted using PLTA to determine the HSE hazards and compatibility with the existing process, equipment, and system at the chosen asset or facility. The PLTA is endorsed by relevant discipline Technical Authority and approved by Head of Asset prior to deployment.

In this paper, the Burke-Litwin Model was used to assess the present technology management and implementation at PETRONAS Carigali's upstream business to find any potential gaps and areas for improvement. As a result of the assessments, proposed changes to address detected misalignments were put in place to strengthen PETRONAS' internal governance documents. The development of the Technology Deployment Framework is expected to aid overall technology management and implementation across the project life cycle. In conclusion, with the right technology project management approach, field application of technology may be more efficient to deliver result at pace. Others could apply the approaches and lessons learned for similar reasons.
A Pragmatic Approach in Well Stimulation at the Late Field Life of Retrograde Gas Reservoir with Condensate Banking, Liquid Loading and Scale Issues: A Meaningful Failure
Authors: Mohamad Ruzlan Nur Syaffiqa , Navaratnam Dharshana , Azman Mohd Fairuz , Ayub Nur Afiqah , Mohamed Arsyamimi , Kamarul Zaman Nur Hazrina , Bernard Caesarsokate , Salleh Khiril Shahreza , Bakar Rizal , Rosland Eadie Azahar
Published: October 2023

Objectives/Scope

Retrograde gas reservoirs with pressure below dewpoint are exposed to severe formation damage and liquid loading issues due to condensate dropout and accumulation in the wellbore. To make matters worse, high water gas ratio leads to another problem like scaling. Historically, methanol soaking, matrix acidizing and nitrogen unloading have proven to be successful in treating these recurring issues during the early years, but it becomes more challenging with aging wells. Therefore, this paper aims to document the undisclosed operational challenges, setbacks and lessons learned for better job planning and execution in the future.

Methods, Procedures, Process

Well performance decline indicates severe skin build up. Pressure survey confirmed the presence of liquid level and Held-Up-Depth (HUD) in the well. The downhole samples were found to be predominantly calcite based on solubility test and Scanning Electron Microscopy (SEM) conducted in the lab. It is critical to first break through the HUD, hence Coiled Tubing Unit (CTU) was deployed to increase the probability of success considering the zone of interest is located inside casing section in a highly deviated well with depth more than 2500 m-MDDF. The treatment program consists of a three-stage process, started with matrix acidizing, followed by methanol soaking to dissolve condensate dropout, and nitrogen unloading to establish flowback post treatment.

Results, Observations, Conclusions

Challenges arise when multiple acid soaking and jetting failed to penetrate the HUD. CTU milling operation then had to be deployed. During the milling process another setback occurred when the circulation failed to be established. Nitrified fluid was first used to establish the circulation yet proved unsuccessful as the reservoir depletion was severe. Loss Circulation Material (LCM) was proposed; but not planned for, hence delaying project execution due to readiness and delivery time. Nevertheless, combination of LCM and Nitrified fluid eventually managed to establish circulation. As the operation resumed, tool stuck occurred, resulted in parts of Bottom Hole Assembly (BHA) to be left in hole. Samples from milling bit that were sent for SEM analysis found to be metal of Iron Oxide, suggesting the casing section may have already collapse.

Novel/Additive Information

Series of unprecedented setbacks call for a pragmatic approach when dealing with an aging well. The conventional method of solving productivity issue need to be improvise with emerging issues of depleted reservoir and compromised well integrity. Advance method of using camera run to confirm HUD type is highly recommended to avoid surprises that would risk job execution.
Managing Safety Risk and Oil Spill During Pre-Breakthrough Steam Flood by Steam Early Detection with Artificial Intelligent
Authors: Triananda Ade Hamzah , Aji Muhamad , Wibawa Ramdhan Ari , Silaban Meita , Pasaribu Rinaldi , Rifani Ria Ayu
Published: October 2023

Delta Area-X is the newest steam flood project in Delta Heavy Oil Field in Riau Province of Sumatra, Indonesia. The area currently produces 12,000 BOPD from 450 oil producers and 145 steam injectors that are supported by high proactive optimization that consists of steam cyclic stimulation, chemical stimulation, and pump optimization. The steam flood life cycle is divided into three general phases: immature phase, transition/steam breakthrough phase, and mature phase. Delta Area-X is currently entering the transition period. The transition phase is the most challenging period because steam has broken through for some producers. Many producer failures experiencing sanding problems, holes in pipes, rapid production changes, scale problems, etc. These are the challenges to completely heat the project area. At this period, the team is supposed to maintain and continue steam injection, conduct cyclic steam in cold producers to connect steam zones, and mitigate steam breakthrough impact on producers by building a fluid level and pinch casing valve. Steam rate reduction in this phase may delay heating area. Delta Area-X has experienced several steam breakthroughs events that caused the production casing line to be cut out and cause oil spills. To prevent similar cases, similar events should be identified earlier to know which wells, where and when for later on leading preventive actions.

Identification started by integrating data from surveillance data from field such as artificial lift, field operation pressure and temperature survey and production performance trend. Artificial intelligence was introduced to the identification process by pattern recognition artificial lift surveillance data to determine indication of steam. The result of Artificial Intelligence combines with dynamic well condition drives condition to meet: gradually detection and sudden detection to oil producer. Since there are many wells operated in the area, an exception signal is required to alert engineers only on wells that has potential issues.

Since application of steam breakthrough signal, the team can quickly make recommendations to manage steam by installing chokes, size up casing choke, reduce stroke per minute (SPM), reduce stroke length (SL) or the most massive action: shut in well oil producer / steam injector. Managing the steam will help controlling the steam causing casing cut out or oil spill and in term of steam flood management, it will redistribute steam to other wells or redirecting steam growth in order to have good sweep efficiency. Since the implementation of this approach, the team has identified more than hundred wells that were captured by steam breakthrough signals, then it followed up with appropriate action that successfully prevented potential safety hazard.
Predrill Geomechanical Modelling and Operational Guidance Helped to Successful Horizontal Drilling - A Case Study from Madura Offshore PSC, East Java, Indonesia
Authors: Panjaitan Julianta Parlindungan , Nurdin Didin , Putranto Heru , Situmeang Andy , Sagita Romi , Chrislianto Renaldi Mikhael , Ghosh Amitava
Published: October 2023

A horizontal drilling is considered to be a challenging drilling operation and require a proper pre-assessment study including subsurface, geomechanics and drilling practice. This paper will be taking the case from East Java basin as one of the prolific basins in Indonesia which are hydrocarbon proven with existence of multiple faults. The prospect Meliwis-2 was planned to be drilled horizontally within such heavily faulted regime. The key drilling challenges in the study area are drilling through the overpressure shale sequences and passing through multiple faults in the carbonate reservoir zone.

A geomechanical model was built using - limited well data combined with regional geological knowledge. Additional drilling information from other wells from nearby field was also incorporated in this study. Based on the offset well(s) review, some of the key challenges were significant drilling problems which mainly occurred after drilling, such as pack off, tight hole while pulling out of hole (POOH) and problems with running casing and wireline logging. Gain and losses were also observed while flow check and POOH the bottom hole assembly (BHA) in reservoir sections. The model that was built at the offset wells was then applied to perform pre-drill wellbore stability and fault stability of the planned Meliwis-2 horizontal well to optimize the drilling plan and minimize non-productive times related to borehole stability. Then the model was subsequently updated during drilling using the actual drilling and petrophysical information gathered from this new well.

The outcomes and recommendations of this study was meticulously followed with the operational guidance by drilling team to complete the well. The well was successfully drilled horizontally with expected data acquisition without any drilling issues due to borehole stability eventhough crossing multiple faults. The well was tested successfully and fulfilled the hydrocarbon expectation. This effort contributed to successful offshore development campaign within tolerance timely execution, budget and no reported HSE events.
Resolving Productivity Mismatched with an Integrated NMR Pore to Production Solution
Authors: Jee Jassica , Azmi Adif Azral , Daud Muhamad Saiful Hakimi , Wong Kent Fui , Lee Samie Sok Foon , Ramdzani Rena Alia , Kalidas Sanggeetha
Published: October 2023

Accurate estimation of reservoir properties such as shale volume, porosity, water saturation, and permeability is vital for reserve estimation and producibility. However, reliance on model-based computations alone can introduce uncertainties if the measured data or core results are biased. This paper addresses the case of Field A in Sabah, Malaysia, where the actual production rate falls significantly below the expectations of the model-based analysis. The observed permeability derived from production modeling based on well-test analysis is considerably lower when compared to log-derived and core-measured permeability profiles. To mitigate these uncertainties and enhance production well modeling, we present a workflow that optimizes the utilization of nuclear magnetic resonance (NMR) from pore to production analysis. The workflow involves deriving a pseudo capillary pressure to determine relative permeability, which serves as an input to reduce production well modeling uncertainty. We discuss four key workflows in this paper.

The first workflow focuses on removing the hydrocarbon effect on NMR T2 distribution to reveal the actual rock properties. Subsequently, NMR Factor Analysis, an unsupervised machine learning technique, is applied to the water-saturated T2 distribution to identify clusters representing unique pore body profiles for each cluster. The following workflow utilizes an automated calibration process that incorporates core-MICP data and machine learning-derived clusters as inputs to generate a continuous capillary pressure-saturation height relationship from NMR and pore throat size distribution index for relative permeability calculations. This workflow provides Production Engineers with an alternative to use NMR-derived relative permeability as an input to calculate the KH window (effective permeability multiplied by thickness) and develop a well-calibrated model for zones without pressure build-up tests. The implementation of this workflow enhances the credibility of the model and reduces uncertainty for production optimization.
Major Greehouse Gas Reduction from Flare Verification
Authors: Mohamad Nor Azli Mohamad Farizal Bin , Seah Shi Ming
Published: October 2023

Membranes are utilized in Acid Gas Removal System (AGRS) at offshore platform to remove carbon dioxide (CO2) from sour gas reservoirs. CO2 selectively permeates the membrane compared to methane and the CO2 rich stream is sent to flare system as permeate flare. This permeate flare is measured by an Ultrasonic Flowmeter (USM) installed as permeate flare meter in 2020. When verification exercises was done, it was first observed that there was a huge discrepancy in mass balance values with the mass output being significantly higher than mass input by 10 to 20%.

Upon verification of the inputs from permeate flare meter to Distributed Control System (DCS), it was initially hypothesized that standard density input assumptions of 0.714kg/Sm3 is unrepresentative of the density values of the supposedly CO2 rich permeate flare. This has caused a large overestimation of permeate flare values.

Operations crew at offshore platform utilized CO2 sampling tubes as a solution for quick sampling of permeate flare and sampling results yielded CO2 compositions of 40 mol% which was the maximum limit of the tubes. Using a conservative approach of assuming the remaining composition of permeate flare to be methane, the permeate flare standard density was then estimated to be at 1.156kg/Sm3. Applying these setting to the input at DCS then yielded an initial 39% decrease to permeate flare values. Meanwhile, third party analysis of permeate flare compositions are conducted on a later date with density values from permeate flare compositional analysis and differing.

The team studied further into the capabilities of the permeate flare meter on live density calculation and proceed to set up trending for calculated density from the meter. The density values calculated by the permeate flare meter were comparable to sampling results. Furthermore, the mass balance between input and output has significantly been improved to be within 3% to 5% of each other. As a result, the team has successfully achieved reduction in reported permeate figure by 4.81 mmscf/d annualized or 97034.26 tCO2e.
Understanding Cement Gaps: A Blueprint for Microannulus Identification
Authors: Singh Kamaljeet , Kumar Apoorva , Dutta Shaktim , Sinha Sahil
Published: October 2023

In many cases, we observe that log responses from ultrasonic, flexural, and sonic logs do not meet the expectations of the executed cementing job without showing major issues. Also, often the logs do not even see the cement behind the casing. These scenarios are most often caused by either a wet microannulus or a dry microannulus. Often the effect of a microannulus is not recognized, and this may lead to the incorrect assessment of cement condition. If this issue is not resolved, it can lead to costly and unsuccessful attempts at intervention.

Successful detection of microannulus was done using the combination of flexural attenuation, ultrasonic pulse-echo technology, third interface echo (TIE) and cement bond log-variable density log (CBL-VDL) measurements. If a dry microannulus is present, ultrasonic acoustic impedance (AI) is more affected than the sonic log and responds earlier to the dry microannulus. If a wet microannulus is present, the sonic log is more affected than ultrasonic AI and responds earlier to a wet microannulus.

In this study, we encountered several wells with varying sizes of dry and wet microannulus. In some wells, a large size dry microannulus was observed and the affected ultrasonic data were mainly showing gas as if no cementing had been conducted. Some wells had a small dry microannulus and the affected ultrasonic measurements showed the annulus to be filled with liquid and cement. Apart from this we also observed several wells with varying sizes of wet microannulus affecting the ultrasonic and sonic measurements by varying degrees and ultimately affecting the cement interpretation.

This work presents the culmination of technological excellence and technical expertise that helped clients to understand the condition of their cement better.
Acidizing Job Optimization in DSF Field New Steamflood Area
Authors: Aji Muhamad , Nugraha Baruna Satria , Irawan Indra
Published: October 2023

Once producer wells experience the impact of steamflooding, they exhibit an increase in temperature, which stabilizes at a certain level, accompanied by a rising trend in fluid and oil production. Subsequently, the wells enter a plateau phase that can last for several years. However, certain hot wells have shown a shorter plateau period and encountered a rapid decline in production, possibly indicating formation damage. This paper provides an explanation of the evaluation process for scale problems and proposes an acidizing solution to mitigate the issue.

The team performed a comprehensive water analysis, evaluating various parameters and comparing the data with those from other areas in the DSF field. The findings revealed that the hot wells in DSF Area-X exhibited a higher scale index, indicating a propensity for calcium carbonate scale precipitation. Considering evaluations from production decline analysis, well maturity, and pump performance, the team proposed an acidizing job utilizing simple acid (HCL) with both bullhead and coiled tubing techniques. The optimization process encompasses opportunity identification, program generation, execution management, and post-job reviews. To expedite and enhance the process, the team leverages digital technology.

The initial results of the acidizing job were highly promising, as the productivity of the wells showed significant recovery, confirming the successful removal of scale from the wellbore. Both the bullhead and coiled tubing unit (CTU) techniques demonstrated similar effectiveness in scale removal. However, the bullhead technique proved more economically advantageous due to its lower cost and faster cycle time. The number of hot wells encountering scale issues continued to rise aligned with the progress of the steamflood process, resulting in an increase in the volume of acidizing jobs. Over the past three years, the team has executed approximately 200 acidizing jobs per year, which have successfully contributed to the recovery of around 1600 barrels of oil per day (BOPD) on an annualized basis. This significant recovery has played a crucial role in improving the base production decline from 45% to 12%.

This paper addresses the prevailing paradigm that scale formation does not occur in new wells. It provides evidence that scale deposition in steamflood fields is accelerated because of temperature rises. This valuable information holds significant benefits for future steamflood projects, particularly within the DSF oil field.
Competency Rulers on Social Performance in Human Rights Management
Authors: Foo Siang Choon , Raja Musa Raja Tatina
Published: October 2023

Company must aspire for its business presence to positively and have strong management of Social Performance where impacts arising from areas of its operation are managed whilst contributing to the society in a responsible manner. The paper aims to demonstrate the need of competency in a Social Performance skill-group in supporting companies in its Human Rights management. Generally, human rights issues that can arise include nuisance to communities, violation of communities’ rights, land acquisition, displacement, environmental degradation to that of forced and child labour. The more recent discourse on human rights is relevant to Climate Change and Just Transition. Therefore, it is important for companies to operate in a manner that adopt human rights management ensuring they respect the rights of affected stakeholders. Fundamentally, personnel appointed to implement these deliverables must have the apt knowledge and skills. In ensuring these knowledge and skills are relevant, a set of competency rulers can be established to ensure the nature of the tasks and deliverables are acquired as a practitioner in human rights management. Overall, the competency rulers must be relevant to indicators and requirements of the work that is relevant to guidance ranging from from United Nations Guiding Principles (UNGP), International Finance Corporation (IFC), International Labour Organisation (ILO) among others. In addition, familiarity with company's internal standards and guidelines are among the necessities for the personnel to execute their responsibilities. As the industry continues to face challenges in complying to legislations, meeting stakeholders’ requirements, expectations and standards pertaining to Social Performance; companies are also expected to demonstrate responsible operations in managing Human Rights. Hence, companies can strive to equip its employees with the right competency. In this case, the competency ruler on Social Performance is exemplary in addressing this.
A Practical Method for Measuring the Liquid Contact Angle of Fracture Proppant Pack
Authors: Zhang Peng , Wortman Philip Bertrand , Guo Boyun , Yang Xu
Published: October 2023

There is lack of a reliable method to determine the liquid contact angle of fracture proppant to characterize its surface wetting property due to the non-flat surface of proppant particle. The objective of this paper is to present and use a new method for determining the liquid contact angle of proppant pack for proppant selection in fracturing oil and gas wells. The water contact angles given by the new method are similar to the contact angles found in literature for the water-air-stainless steel 304 system and the water-air-copper system. The difference is 3%~3.5%, indicating that the new method is valid for determining liquid contact angles on the smooth surfaces of solids. The new method was compared with the sessile drop method for four water-particle pack systems where stable drops were established. The difference in estimated liquid contact angles is between 0.41% and 7.12%, indicating that the new method is valid for determining the liquid contact angles on the rough surfaces of particle packs. The new method was applied to estimating the water and oil contact angles on the surfaces of packs of 11 commercial fracture proppants. Comparison of derived water and oil contact angles suggests that all these proppants are oil-wet proppants. Two proppants are considered more water-wet than other proppants because of their lower water contact angles. Although one proppant was claimed by its manufacturer as oil-wet proppant, its low water contact angle suggests that it is a water-wet proppant. It was observed that liquid contact angle of proppant pack is not sensitive to proppant size for given types of proppants in the range of proppant size tested. The new method requires only drop volume and the wet diameter/area of the proppant pack to derive liquid contact angle. Even a liquid drop sinks into a proppant pack, the contact angle can still be estimated if the wet diameter/area is measurable. The new method may not be accurate in situations where the proppant particle size is so large that the liquid drop sinks into the pore space of the pack without leaving a circular wet area at the pack surface. Further investigations are needed to establish the critical size of the particle size. The liquid contact angles given the new method are dynamic contact angles if the liquid drops are not in thermodynamic equilibrium. The results are good only for comparison of surface-wetting behavior of particles, not for scientific but engineering uses.
Pressure Depletion Integrated Static Reservoir Model as Development Planning Basis in Mature Handil Field
Authors: Erriyantoro Eros Sidney , Muhroni Toni Okto , Suardiputra Aditya , Suwito Edy , Sianturi Julfree , Utama Fia Adhi
Published: October 2023

Handil is a mature swamp oil and gas field located in Mahakam Delta, East Kalimantan, Indonesia. Hydrocarbon is accumulated within series of multi-layered reservoirs, which are mainly channels and crevasse splay by facies. This study focuses on Handil Gas Pool, also known as Handil Deep Zone interval. This stratigraphic interval is the deepest and primarily produces gas through a depletion drive production mechanism. The unavoidable reservoirs pressure depletion occurred with high variation across the field. Still, Handil is expected to face upcoming aggressive drilling campaign. Therefore, the evaluation of the field remaining stakes becomes even more crucial, particularly for Handil Gas Pool interval, which represents the deepest development target.

Conducting a more conventional reservoirs study method, such as history matching with a dynamic model, in Handil Gas Pool context can be relatively complex and resources-consuming. This complexity arises due to the need for regular updates with newly drilled well data. Nevertheless, identifying and location reservoirs pressure depletion remains key to optimizing future development targets. Hence, a more efficient and practical solution has been deemed necessary to overcome these challenges.

The methodology used in this study was based on integrating reservoir pressure depletion into the static reservoir model. The workflow incorporated dynamic data synthesis, production history and allocation analysis, as well as reservoir pressure estimation through P/z analysis. The study also introduced the definition of Reservoir Pressure Unit (RPU), which served as the basis for modeling and analysis. By estimating and applying the current reservoir pressure, a depleted static reservoir model was generated, representing the current Remaining Gas-in-Place. Furthermore, the volume estimation of booked undeveloped reserves was taken out from the model.

This comprehensive approach resulted in a Producible Gas-In-Place model that can be utilized for estimating and proposing future development targets. The implementation of a well-designed automated well screening workflow, in combination with a detailed dynamic review, facilitated the identification and optimization of future development targets. Among more than 70 initial well candidates, over 20 have been identified as having potential above the current economic threshold. The findings demonstrate the efficiency and practicality of the proposed methodology in identifying future development well targets and its potential for application in similar mature gas fields.
A New Artificial Lift Approach in Telisa Low Productivity Reservoir: Utilized Very Low-Rate ESP
Authors: Aryanto Agus , Malau Aldani , Hanuranto Heru Trisakti
Published: October 2023

KS field faces low production challenges from Telisa formation. In addition, other problems in Telisa formation are also high GLR and solid production. ESP equipped with sand control and gas handler can still be used for liquid production above 100 BLPD. The problem is that the rest of the wells producing from Telisa formation that still use gas lifts, the production of which is already below 100 BLPD. In this case, the usual ESP configuration is no longer be used. The production method with gas lifts can no longer be used due to the limitations of gas production which continues to decline. Currently, there are still more than 30 wells that use gas lift and to maintain production from these wells, the right artificial lift solution must be sought. A modification has been made to the ESP artificial lift to be able to accommodate the very low production rate. The trial has been carried out in KS-001 and KS-002 for more than 1.5 years and as the result, the ESP is still running normally today.

To improve run life for low rate ESP which may exposed to down-thrust condition and increased temperature resulted from low cooling fluid pass thru ESP motor housing, several precautions must be taken during designing ESP which fit for application: Pump with compression stages construction were selected for low rate application. This compression stages design will improve down-thrust handling in the pump. Down-thrust force generated by pump will be transferred into protector thrust bearing, where the thrust bearings were covered with lubrication oil. High load thrust bearing were selected to handle the thrust load. Tandem BPBSL – BPBSL protector selected to give extra motor oil reservoir to the ESP motor in the case of motor run on higher temperature due to low cooling fluid passes thru ESP motor housing. Due high GOR up to 800 SCF/STB, with ability to handle free gas up to 45% GVF, combination of Advance Gas Handler and gas separator were selected for better handling of free gas produced by the well. In low flow rate ESP system, fluid velocity pass thru the ESP motor housing is essential for cooling system. In the case of KS-002, well was completed with 7″ casing. ESP casing shroud were selected to improve fluid velocity.

In overall ESP parameter in 2 wells trial are in normal condition, even though running with low frequency and limited liquid rate. Application of tandem protector, gas handling device, and sand screen successfully handle very low liquid rate with high GOR in hydraulic fractured wells. With the success of ESP's very low rate in Telisa, there is no longer any concern if gas production decreases.

This paper will describe an integrated application of very-low rate ESP in sandy gassy wells with low productivity. These applications are required to improve the run-life of the ESP in Telisa zone to minimize oil deferment.
Assessment of Different Field Development Strategies Deploying Maximum Reservoir Contacting (MRC) Well in Carbonate Reservoir: A case study of Oilfield R
Authors: Jia Han , Tong Min , Peng Hui , Deng Xili , Song Ruixuan , Wang Rui
Published: October 2023

Deploying horizontal well is one of the efficient methods to enhanced oil recovery. Maximum Reservoir Contact (MRC) well, based on the horizontal well, which indicates the contacting area of wellbore and reservoir should be as large as possible to obtain the optimum exploration effects.

The purpose of this paper is to build an assessment and optimization work-flow, which guides the well pattern improvement and well-type selection via a case study of the filed R in a Middle East Carbonate Reservoir. Analyzing several field development index, like production performance, gas oil ratio, water cut, pressure, etc. in a pilot-scale well pattern both for the conventional horizontal wells and MRC wells using different injection schemes, including injection timing, injection volume, and injection components, via reservoir numerical simulation.

The method using to evaluating reservoir exploration effect in this paper is numerical simulation, assuming different development strategies and well-type, via reservoir numerical simulator. Control-variate method as well as used in this study, which focus on keeping single factor analysis for the simulation. Comparing all the field development indexes among different cases while keeping other factors consistent, for example, exploring the influence from well types, which are MRC well and conventional horizontal well, two cases must be deployed the same injection schemes.

Simulating different cases with analyzing the results, MRC wells obtain the better oil production generally compared with conventional horizontal wells. However, oil production performance is not the only index which is cared for in oil & gas industry, additionally, in terms of reservoir engineering, water cut, water breakthrough, gas breakthrough, gas oil ratio, oil steady production plateau, etc., while some economic indexes are extremely concerned by the experts and companies. Consequently, assessment of MRC wells effect should consider many factors from the perspective of oil & gas industry. Well trajectories adjusting with target layer or reservoir is also the MRC technique, optimization of well trajectories profits the production performance both for MRC wells and conventional horizontal wells.