bluuebunny/crossref_metadata_2025 huggingface dataset:
Dual Function Hydrate Inhibitor for Prevention of Hydrate in Methane and Carbon Dioxide System
Authors: Kassim Zamzila , Rahman Fadhli Hadana , Lal Bhajan
Published: October 2019

Dual function hydrate inhibitor (DFI) is envisaged to provide superior inhibition performances for controlling hydrate formation in comparison to conventional thermodynamic (THI) and kinetic hydrate (KHI) inhibitors. In this work, the performance of DFI was evaluated in high pressure Sapphire cell for methane (CH4) and carbon dioxide (CO2) system. The effects of DFI to the hydrate phase equilibrium conditions at various concentrations for both CH4 and CO2 system were measured in a pressure range of 3.90 – 8.30 MPa and 1.9 – 4.5 MPa respectively. The DFI is then being evaluated for KHI for CH4 and CO2 at 80 bar and 3.5 bar respectively at 274 K experimental temperature. Furthermore, the analysis of induction time and relative inhibition performance are presented for CH4 and CO2 in the absence and presence of DFI. The DFI inhibition performance is strongly evidence as it is observed able to shift hydrate equilibrium conditions, while at the same time prolong the hydrate induction time. In addition, hydrate dissociation enthalpies are also calculated for both considered systems and it was found the enthalpies are within the range of conventional hydrate formation, therefore it is evidence that DFI is not involved during the hydrate cages formation. DFI ability to simultaneously act as THI and KHI shows that DFI performance is more superior as compared to the conventional THI.
Simple and Effective Steps to Generate Opportunities in a Mature Field: Challenging Historical Data and Defying the Established Understanding
Authors: Abdulhadi Muhammad , Mansor Najmi , Tran Toan Van , Chin Hon Voon , Jacobs Stephen , Suggust Alister Albert , Usop Mohammad Zulfiqar , Huong Chii Seen , Zamzuri Dzulfahmi , Abdussalam Khomeini , Khalid Aizuddin , Munandai Hasim , Yusop Zainuddin
Published: October 2019

While it is true that reservoir simulation and new technology applications are crucial to unlocking reserves in a field, the first and most fundamental step in rejuvenating a mature field is to verify the existing data and evaluate the basis of the current understanding. This process, while seemingly "routine", can uncover ambiguous data and questionable interpretations, which can mislead the reservoir simulation results unless corrected. The older and more mature the oilfield, the more ambiguities that can be uncovered. The new understanding can be subsequently converted to "quick-gain" opportunities that can be quickly monetized, while maturing higher investment and more complicated opportunities with reservoir simulation.

The approach applied in a sample field named Field B comprised challenging the established interpretation and understanding by taking a more thorough look and applying a different approach with the basic data. There are examples of reinterpreting the seismic data, cross-checking pressure and production reports with geological understanding, cross-checking well intervention reports, production and open-hole log data, and challenging the conventional approach and understanding. On top of the detective work, it is also necessary to judge whether the data "make sense" or seem unreasonable. Although simple, this approach was effective and successful in generating multiple opportunities in Field B.

This paper provides valuable insight and examples in data verification and challenging established understanding to generate potential opportunities. Having a good grasp of the fundamentals is a valuable skill in a mature field environment. It pays to thoroughly understand the fundamentals, because otherwise, the "fancy techniques" will not work.
Performance Improvement of Thickened Liquid CO2 by Introducing a Philic-CO2 Silicone Polymer
Authors: Li Qiang , Wang Yanling , Li Qingchao , Wang Fuling , Bernardo Jennifer , Zhang Ye , Bai Baojun , Liu Fei
Published: October 2019

As an excellent stimulation treatment for the shale reservoir, CO2 fracturing liquid is injected into the reservoir to increase crude oil production due to the high mobility and high backflow. Nevertheless, many disadvantages in fracturing process, including high fluid loss volume, short fracture length and low viscosity of pure CO2, hinders its application and development. In this investigation, a novel silicone thickener consisted of CO2-Phobic Phenyl and CO2-Philic Ester group is prepared. The thickening performance of a thickener in liquid CO2 is measured by capillary viscosity measurement system at different conditions. Molecular simulation presents that a mesh structure can be formed among CO2, solvent and silicone, and the density of mesh structure affects the viscosity of thickened liquid CO2 Meanwhile, the filtration property and fracturing simulation are compared between pure CO2 and thickened CO2. With the capillary viscometer, the viscosity of thickened liquid CO2 can be increased to 2 mPa·s at 3 wt% thickener at 303 K and pressure of 12 MPa. An increasing CO2 viscosity was displayed as the thickener content and pressure increased, but a decrease of viscosity is shown as temperature and flow velocity rise. The elevated viscosity leads to a significantly reduced filtration volume. Fracturing simulation displays that the increased viscosity results in a longer fracturing time and length. By analyzing the fracturing simulation data, the thickener CO2 can involve a farther reservoir which the pure CO2 cannot reach. Compared to pure CO2, a 55m fracture is revealed during the fracturing simulation while it is only 6m for pure CO2. For the fracturing and filtration performance, the thickened CO2 is obviously better than the pure CO2. The addition of thickener can not only obviously improve the CO2 viscosity to some degree, but also the excellent fracturing and filtration performance according to the extended finite element simulation and the thickened CO2 is considered as an applicable fracturing fluid to develop the shale reservoir.
Assuring Groundwater Safety with Stable Isotope Monitoring Method for Waste Slurry Injection Project, Duri Field, Sumatra, Indonesia
Authors: Yuniar Yuniar , Sugiarto Ari , Syahputra Ahmad , Dwi Hadian M. Sapari , Barkah M. Nursiyam , Satrio Satrio
Published: October 2019

Shallow groundwater is the primary drinking water source for local communities surrounding Duri Field operations area. To ensure the local community has access to safe drinking water and to comply with Government of Indonesia (GOI) environmental safety regulations, PT. Chevron Pacific Indonesia (PT CPI) established a groundwater monitoring system to ensure that slurry waste injection into deep non-potable water aquifers does not contaminate nearby shallower drinking water aquifers. The prevention system also includes well integrity surveillance and monitoring as a leading indicator and water sampling and analysis as a lagging indicator.

Duri Field is in the Rokan block, Riau Province of Indonesia. Oily sand and viscous fluids are byproducts from oil production and treatment processes. The Sand Management Facility (SMF) was developed to manage these solid and liquid wastes by injecting mixed waste slurry under high pressure into deep subsurface formations. The scope of this study included 12 injector wells with two groundwater monitoring wells surrounding each injection well.

Stable isotope monitoring technology is used to ensure that deep waste injection slurry is not mixing with and contaminating shallow drinking water resources. Stable isotope (δ2H, δ18O) analysis was used to define the Local Meteoric Water Line (LMWL) of Rokan Watershed defined by equation δ2H = 7.6 δ18O + 10.5 (r2 = 0.921), which is applied as a reference point for isotope studies in SMF area. The stable isotope δ2H samples for groundwater in SMF ranged from −70.5 ‰ to −25.1 ‰ followed by formation and surface waters that respectively ranged from −64.8 ‰ to −48.9 ‰ and from −61.9 ‰ to −20.8 ‰, while δ18O samples ranged from −11.18 ‰ to −2.12 ‰.

After four years of monitoring, δ2H and δ18O results indicate that the shallow groundwater samples are coincident with the reference meteoric water line, which implies these samples originate from rainwater. Surface water samples are consistent with water influenced by evaporation processes. Conversely, samples of produced waters exhibit a distinctly different isotope character compared to the shallow water samples. This suggests that there is no connection and mixing between surface and shallow aquifer with the deeper slurry injection zones.

Stable isotope analysis has proven to be a successful groundwater monitoring technique and is an enabler for continued safe injection of slurry wastes into the deep subsurface. These efforts have been acknowledged by Kementrian Lingkungan Hidup dan Kehutanan (KLHK) of GOI experts as one of the most advance groundwater monitoring technologies currently in use in the Indonesian oil and gas industry.
Water Injection Performance Benchmarking & Replication of Best Practices Reduces Operating Cost Improves Recovery
Authors: Faiz M. Faridyl , Mandal Dipak , Masoudi Rahim , Mustapha Syarizan , Wahab M. Afiq , Nasron Budi Mawardi , Hadi Sriyanta
Published: October 2019

Water injection (WI) to improve oil production and increase reserves had been practiced in Malaysia since 1990s. Currently, around 27 fields are producing with water injection. To better manage these WI fields and gauge the relative performance of these fields, certain Key Performance Area (KPA) and Key Performance Indicators (KPI) were identified. Measurement of these KPA and KPIs serves as a yardstick to compare performance of WI fields and thus provide measures to improve collective performance by promoting replication of best practices and sharing lessons learnt.

In the era of digital technology, the periodic measurement of KPA and KPI has been automated using the existing online platform which can remain accessible to all related parties. It provides a platform for data visualization with simple look forward analysis. The WI data is stored in company databank and the performance dashboard can be viewed from existing software. The team managed to overcome the challenges in completing the historical data gap and data hygiene which previously were managed manually and were not integrated. This resulted in historical evaluation of KPAs and KPIs of certain fields.

This automation initiative will enable practicing engineers to identify the value leakages and proposed mitigation efforts. Some of the best practices identified such as pipeline pigging optimization, correct biocide dosage, periodic calibration of flow meter and chemical optimization already helped to reduce operating cost in certain WI fields.

With these efforts, the company could reduce the operating cost significantly in year 2018. Other than data visualization, the tool provides diagnostic plots such as Hall Plot, Chan's Plot etc. for quick analysis of signs of well/ reservoir health deviations and thus solutions could be provided proactively. On seeing the initial positive results, this tool is being tried for the rest of the WI fields.

This paper details how this tool tries to diagnose all sub-optimal areas within various WI project simultaneously, which leads to operational excellence and improvement in oil recovery, by identifying value leakages, providing proactive solutions with replication of thus identified best practices. Additionally, usage of this tool to rank WI performance of different projects can potentially help to initiate competition between different operators for improvement.
A Case Study of Miscible CO2 Flooding in a Giant Middle East Carbonate Reservoir
Authors: Wu Shuhong , Fan Tianyi , Zhao Lisha , Peng Hui , Tong Min , Wang Ke , Wang Cong
Published: October 2019

Miscible CO2 flooding is a proven field development technology, which has been widely applied to many fields to enhance the oil recovery. It can efficiently expand oil volume, reduce oil viscosity and eliminate oil-gas interfacial tension. In this paper, a case study is detailed on CO2 flooding in a giant low-permeability (2-5md) and low-viscosity (0.3mpa.s) carbonate oil reservoir in Middle East, which has been extensively developed since 1990's with natural depletion, water flooding, and hydrocarbon gas (HC) flooding as well as HCWAG. The demand for further enhancing oil recovery and reducing greenhouse gas emission requires to assess the potential of CO2-EOR flooding.

In this paper, production history is firstly reviewed as well as the CO2 pilot test, including production performance, gas/water injection profile and remaining oil distribution in a five-point high-angle horizontal well pattern. MMP of hydrocarbon gas and CO2 is compared in the carbonate reservoir with the miscibility with oil, miscible area, residue oil and also, the gas intake profile as well as gas breakthrough. The density difference between gas/CO2 and oil results in a gravity override, gas/CO2 channeling, and early breakthrough and poor vertical conformance problems. Therefore, CO2-alter-Water injection with optimized WAG cycle as well as tapered WAG are detailed to improve production performance and increase the oil recovery, which is considered as a potential way with high swept efficiency of water flooding (70-80%) in a low-viscosity and high displacement efficiency of CO2 miscible flooding (85-90%).

The discussions of simulation schemes in this study can be applied to determine the optimal strategy for the future development of this large carbonate reservoir in the Middle East.
Novel Method for Estimating SHmax in Naturally Fractured Formations Using DFIT Data: Case Study on Unconventional Shale Gas
Authors: Leem Junghun , M Ali Siti Syareena , Tan Chee Phuat , Kantaatmadja Budi Priyatna , Che Yusoff M. Fakharuddin , Md Zain Zahidah
Published: October 2019

Maximum horizontal stress (SHmax or SH) and associated horizontal stress anisotropy are some of the essential inputs for drilling and completion optimization such as 3D geomodel and geomechanical model building, drilling mud design and well trajectory analysis, solid production prediction, sweet spot identification in tight/shale plays (i.e. low stress anisotropy as well as high brittleness), and multi-stage hydraulic fracturing design optimization with stress shadowing analysis (e.g. well spacing, fracturing stage spacing, injection rate, fracturing fluid, proppant, etc.).

Minifrac/Diagnostic Fluid Injection Test (DFIT) prior to hydraulic fracturing can provide essential reservoir information, such as closure pressure (e.g. minimum horizontal stress, Shmin or Sh), formation pressure, and effective permeability from the G-function analysis. Nolte and Smith (1981) identified Pressure Dependent Leak-off (PDL) behavior in the G-function analysis, and defined PDL net pressure to estimate SHmax associated with small fissure opening along the main hydraulic fracture during the Minifrac/ DFIT. The definition might be suitable for estimating SHmax for non-fractured formations such as conventional ductile sandstones, which could create small fissure openings (e.g. cm size) along the main hydraulic fracture. However, in conventional and unconventional fractured formations such as fractured carbonates, tight sandstones, and shales, the methodology was not applicable because of limitation in the assumptions, which excluded interaction with existing natural fractures (i.e. natural fracture opening during the Minifrac/DFIT).

A novel methodology has been developed to estimate SHmax in conventional and unconventional fractured formations from Minifrac/DFIT field measurements. The SHmax Estimation from DFIT method (SHED) is considered more direct compared to the existing methods, since the common industry-accepted methods, such as the image log method from breakouts and the poroelastic horizontal strain method, require Shmin inputs from Minifrac/DFIT tests, additional logs such as image logs and sonic logs, and additional image and geomechanical analyses to define SHmax. Whereas, SHED only requires Minifrac/DFIT test data, typical G-function analysis, and natural fracture patterns from existing geological maps and other inputs, such as seismic surveys and Discrete Fracture Network (DFN) analysis. SHED has been validated and applied in several unconventional shale gas fields utilizing available Minifrac/DFIT field measurements.
Hybrid Drill Bit Technology on Performance Motor Bottom Hole Assembly Yields Breakthrough Drilling Performance in Kuwait
Authors: Al-Baghli Waleed , Al-Salamin Mohammad , Sulaiman Sulaiman , Abdelhamid Atef , Alnemer Ali , Pandya Mehul , Agawani Waleed
Published: October 2019

Operators in the current volatile oil and gas industry must optimise drilling performance and minimize well cost. Various drilling tools and methods have been implemented over the years to improve drilling efficiency and to reduce the non-productive time (NPT) while drilling through challenging formations. Many North Kuwait onshore wells are drilled with conventional drill bit technologies, such as tungsten carbide insert (TCI) and polycrystalline diamond compact (PDC) bits on either rotary or performance motor bottom hole assemblies (BHA). This paper discusses the breakthrough drilling performance of 16-in. hybrid drill bit technology on a performance motor BHA, delivering outstanding results and savings for the operator. The typical 16-in. vertical section ranges from 4000 ft. to 5000 ft., and contains limestone and sandstone with interbedded layers of shale and streaks of anhydrite with high variance in the unconfined compressive strength (UCS) across these formations.

The downhole environment is unsuitable for PDC bits due to impact damage from the variable UCS, and TCI bits provide unsatisfactory rates of penetration (ROP) requiring a new drilling approach for the application. Poor dull conditions combined with the long section led to low overall ROP, further indicating the need for a new class of bit.

The engineering process involved reviewing: –Current TCI and PDC cutting structure designs–Surface drilling parameters applied–Post-run dull analysis from current bit designs–Previous TCI and PDC bit design performance on rotary and motor BHA–Hybrid design performance on rotary BHA

A collaborative technical analysis identified key performance objectives to ensure a step change in section drilling. Hybrid drill bit technology was deployed on a performance motor BHA to enhance the ROP. The hybrid bit enhanced the ROP by 153% with a 52% reduction in cost per foot compared to the average TCI performance in this field, saving the operator 2.2 days and over $ 0.4 Million operational cost.

The hybrid drill bit design demonstrated its ability to serve as an alternative to conventional technologies and showed the potential for efficient drilling and reduction of NPT over multiple wells, assisting operators in the current cost-sensitive industry environment.
Back to Basics: How a Field in Offshore Sarawak Optimize Production and Maximize Recovery Via Analytical Approach
Authors: Abd Rahman Noor Shakila , Zamzuri Mohd Dzulfahmi , Abd Wahid Muhammad Izad , Jamaluddin M Helmi
Published: October 2019

Field XX is a mature field located in offshore Sarawak with relatively low RF due to reservoir complexity and compartmentalization. Previous development campaigns focused on specific compartments, while future development plans are targeting less developed compartments to increase the field-wide recovery. This paper is intended to discuss the methods and the success story of production optimization and recovery maximization effort from developed reservoirs: Classical Method: Data and analysis integration allows identification of unswept oil and behind casing opportunities (BCO). The approach begins with incorporating reservoir maps and correlations with current fluid contacts (from reservoir performance and logging data), pressure trending, production bubble maps etc. Identified opportunities are further evaluated using MBAL and Prosper models to de-risk the potential.Dumpflooding: From wellbore utilization review and reservoir performance analysis, in situ dumpflood candidates can be identified. In Field XX, most wells are completed in multiple sand sequences, which open up the opportunity to utilize water-producing reservoir to naturally flood the depleted reservoir via pressure difference in shut-in conditions.Drainage Optimization: Over the production life, numerous development wells were drilled and completed targeting specific reservoirs. After decades of production, adjacent wells started to feel the interference of the other, creating a sub-optimal production condition. Via gross rate vs. top node parameter analysis, well drainage optimization opportunity can be achieved by shutting less productive well to allow the better to continue producing at a higher potential.

Using analytical reservoir engineering, Field XX managed to achieve the following: (A) identified 2 unswept/attic oil BCO to increase RF in respective reservoir by 2-4%; (B) implemented drainage optimization to increase the technical potential by 40% and delay water table progression by shutting in the downdip neighbouring well; and (C) identified a dumpflood candidate to provide pressure support prior to a more comprehensive water injection project in the future.
Management of Artificial Lift Planning & Deployment for Improved Field Development Plan
Authors: Haryanto Elin , Yersaiyn Saltanat , Shah Abdur Rahman , Su Shi , Bouchet Francois
Published: October 2019

Artificial lift is generally required to extend field-life beyond the period of natural flow. In the course of the reviews and studies we performed, we noted artificial lift had not been given sufficient consideration at initial design phase. Due to the pressure to maintain the field production, operators often choose a phased artificial lift deployment to cope with the learning curve, risks and uncertainties, which typically includes: ▪A first phase (Phase-1) of artificial lift is screening and concept testing to evaluate artificial lift options;▪A second phase (Phase-2) involves deployment to a group of wells for a selected option;▪A final phase (Phase-3) is the full field implementation.

This paper presents an efficient and effective workflow to select the most suitable candidates for Phase-2. Lessons learnt based on the implementation of workflow in real-life case studies will be shared as well: ▪First, a well selection process is performed to review inactive strings and/or low performers that are most impacted by such issues as reservoir pressure declined / high water production. Cased-hole saturation logs (PNC log) and static pressure log measurements are used to build an understanding of areal pressure and water saturation distribution and to further identify localized pressure sinks and watered-out areas. The understanding gained upon reviewing the well-based surveillance data is used to identify candidates for artificial lift application.▪Then, the well candidates which are grouped by categories of issues and different reactivation options are screened for each group of wells. A score-based ranking process is applied to sort candidates on urgency, value or impact of artificial lift and possibly other criteria, using production history and surveillance data.▪Finally, results per well are reconsolidated to reservoir / field level and used to support a field-wide concept, which allows to extract valuable field scale requirements (e.g. the determination of the gas-lift volume requirement for gas-lift planning etc.).

This workflow greately helps to understand the root cause of performance issues and to select the most suitable artificial lift concept (including considering well pre-conditioning needs such as water shut-off). It leads to exploring and defining artificial lift concepts and helps to focus on the field development plan and detail engineering study at a very early stage.
Reservoir Recovery Estimation Using Data Analytics and Neural Network Based Analogue Study
Authors: Chen Yajing , Zhu Zhouyuan , Lu Yangxiao , Hu Changhao , Gao Fei , Li Wei , Sun Nian , Feng Tian
Published: October 2019

Reservoir analogue study, which is different with flow physics based prediction methods such as reservoir simulation, is based on human experience and knowledge from skilled reservoir engineers. In this work, we present a new workflow to replace the human knowledge-based analogue studies with data analytics and machine learning techniques.

First, we collect reservoir properties, development parameters, and historical recovery data for 1381 actual U.S. oilfields from Tertiary Oil Recovery Information System (TORIS) by U.S. Department of Energy. We conduct extensive data cleaning for outliers and missing values. Then, we determine the most important determining factors for recovery factors. We further use single-variable and bi-variable analysis to understand relationship between recovery factor and determining factors. Finally, we use train an Artificial Neural Network (ANN) model to make recovery factors predictions.

We have found that the recovery factors mostly depend on 19 principal factors, a reduction from a total of more than 70 properties originally in TORIS. We randomly select data from 90% of these oilfields as training set for machine learning. The predictability and accuracy of such methodology is tested by making recovery forecasts for the remaining 10% oilfields and by comparing the forecasts with the actual recovery factors. Eventually, the average error in recovery factor predicted by the trained ANN model is about 10%. Overall, this methodology has shown strong performance in computer assisted analogue study, which shows minimum requirements on human knowledge and hands-on work to study these 1381 oilfields.

This work provides a new workflow of using data analytics and machine learning techniques for reservoir analogues studies. Reservoir engineering software systematically built based on this methodology can serve as more efficient and accurate predictive tool in studying reservoir analogues.
2nd Chance - An Interactive HSEQ Event and Initiative Reporting System for Improving Performance in Well Intervention Division
Authors: Siswanto Agus , Therademaker Ricky , Ramli Rafiansjah
Published: October 2019

The Health, Safety, Environment and Quality (HSEQ) reporting system is used in Well Intervention (WLI) Division of PT Pertamina Hulu Mahakam as one of Oil and Gas Company. WLI operations are considered massive with 21 barges and 890 workers. The barges are spread out onto 6 production sites. They can generate substandard act / situation, Downgraded Situation (DGS), incident, or deviation toward the HSEQ procedure. It shall be monitored and rectified to avoid any escalation and avoid repetition.

As part of HSEQ Management System implementation, HSEQ initiative program need to be monitored its progress to achieve Company's Objective (lagging indicator). The initiatives consist of audit/ inspection, emergency drill, meeting, and visit.

The need of database recording system is unavoidable to manage the operations accordingly. It triggers the development of reliable and user friendly application to learn from the event and initiative reporting system. The application is officially launched in mid of 2017 after 6 months of development.

2nd Chance is developed internally by considering Company Rule, operational user expectation and experience operating in Mahakam field. The reporting system consists of HSEQ Anomaly, Downgraded Situation (DGS), Incident and Initiative. The tool is accessible everywhere with Company's network access (intranet), capable to accommodate all essential information with smart interactive features i.e. user friendly and able to avoid unnecessary mistakes. It is equipped with automatic graphical dashboard to analyze the trends.

Company's Objective is to obtain zero Loss Time Incident (LTI) operation could be achieved by the management of learning from the event as continual improvement process. WLI Division achieves 540 days without LTI with 5.33 million man-hours in 2017 - 2019.
VSD Setting: ESP Motor Current-Feedback, An Effective Approach to Mitigate High Gas Interference Problem in Gassy ESP Well - Case Study SK-0178
Authors: Amijaya Winandar , Kusuma Hendra , Narso Narso , Sudibyo Geraldus Yudhanto
Published: October 2019

Gas Interference is one of the main difficulties in ESP Operation. High gas interference might reduce the pump volumetric efficiency (lower liquid production) and in the worst situation might stop the pump operation due to Gas Lock. In longer operation, it might even damage the motor due to frequent start-stop.

ESP at SK-0178 installed in Nov-2016, and directly having problem with High Gas Interference & Gas lock (frequent underload alarm) resulting 3-4 times shutdown daily. Several troubleshooting steps have been taken:

Venting the annulus gas: Resulting no shutdown, could handle the gas issue but not an environmentally friendly solution and wasting valuable gas production (200 KSCFD) VSD - PIP (Pump Intake Pressure) feedback: Resulting no shutdown, but ESP operated with fluctuating load and with lower production rate (gas interference, dropped by 40-60 BOPD)

Detailed discussion with technology provider and reference case study come up with a proposal to trial New VSD Logic: Motor Current Feedback. The logic worked immediately after it is applied. All pump parameters (Frequency-Hz, Motor Load-A, PIP-Psig) shortly monitored to be stable unlike the previous PIP-feedback mode. The logic works better for high gas interference condition. It keeps the pump from having an accumulated gas inside the impeller-diffuser, hence preventing the pump from the possibility of having gas lock condition. Well test performed after the mode-change also showing a return to normal production. In longer monitoring period, the pump also showing a stable operation, thus we can say the approach is successfully mitigating the high gas interference ESP case in SK-0178: No shutdown, saving 200-KSCFD gas and 120-BOPD production.
Sumatera Operation SMO Integrated Optimisation Decision Support Center IODSC Success in Embracing Digitalisation and Innovation to Deliver Business Results
Authors: Susanto Ivan
Published: October 2019

This paper will describe the success of Chevron Pacific Indonesia's (PT. CPI) Sumatera Operation (SMO) to deliver improved business results through the implementation of an Integrated Optimization Decision Support Center (IODSC). The SMO IODSC is focused on value optimization across the Rokan Production Sharing Contract (PSC) by developing and implementing digital solutions ranging from the simple, such as Short Message Service (SMS) gateway to monitor rig status, through to the more advanced, such as Artificial Intelligence to identify failing equipment. Value creation was achieved by the systematic adoption of digital solutions to reduce lost production opportunity (LPO), reduce expenses, improve energy efficiency and optimize hydrocarbon production. Key to this systematic adoption is IODSC's Integrated Exception Management (IEM) system. IEM supports CPI employees in their daily tasks by:

Managing large amounts of data captured each day and using data science to change it to actionable information. Capturing exception criteria based on Subject Matter Experts (SME) knowledge that automatically identifies and prioritizes wells and equipment operating outside the desired condition (exception signals). Housing workflows to enable review, action and close-out of the exception signals.

IEM provides "one-stop exception review" and "start to finish workflow" capabilities that documents accountability for each step of the workflow and the time taken to complete. IEM allows for the exception criteria to be defined by physical principles, subject matter expert (SME) knowledge, or Artificial Intelligence (AI)-based techniques.

As a result of this systematic implementation of improved workflows and digital solutions, within 2 years of commencement the IODSC exceeded it's 5 year value creation target.
Application of Design of Experiments for Well Pattern Optimization in Umiat Oil Field: A Natural Petroleum Reserve of Alaska Case Study
Authors: Gurav Yojana S. , Dandekar Abhijit Yeshwant , Patil Shirish L. , Patwardhan Samarth D.
Published: October 2019

Umiat field, located in Alaska North Slope (ANS) poses unique development challenges because of its remote location and permafrost within the reservoir. This hinders the field development, and further leads to a potential low expected oil recovery. The objective of this work is to assess various possible well patterns of the Umiat field development, and perform a detailed parametric study to maximize oil recovery and minimize well costs using statistical methods.

Design of Experiments (DoE) is implemented to design simulation runs for characterizing system behavior using the effect of certain critical parameters, such as well type, horizontal well length, well pattern geometry, and injection/production constraints on oil recovery. After carrying out simulation runs using a commercially available simulation software, well cost is estimated for each simulation case. Response Surface Methodology (RSM) is used for optimization of well pattern parameters. The parameters, their interactions and response are modeled into a mathematical equation to maximize oil recovery and minimize well cost.

Economics plays a key role in deciding the best well pattern for any field during the field development phase. Hence, while solving the optimization problem, well costs have been incorporated in the analysis. Thus, based on the results of the study performed on selected parameters, using interdependence of the above mentioned methodologies, optimum combinations of variables for maximizing oil recovery and minimizing well cost will be obtained. Additionally, reservoir level optimization assists in providing a much needed platform for solving the integrated production optimization problem involving parameters relevant at different levels, such as reservoir, wells and field. As a result, this optimum well pattern methodology will help ensure optimum oil recovery in the otherwise economically unattractive field, and can provide significant insights into developing the field more efficiently.

Computational algorithms are gaining popularity for solving optimization problems, as opposed to manual simulations. DoE is effective, simple to use and saves computational time, when compared to algorithms. Although DoE has been used widely in the oil industry, its application in domains like well pattern optimization is novel. This paper presents a case study for the application of DoE and RSM to well optimization in a real existing field, considering all possible scenarios and variables.
Revealing Hidden Potentials to Maintain Production by Using Integrated Petrophysical Interpretation Techniques in Mahakam Mature Fields
Authors: Hidayat Haris , Supriady Supriady , Anwar Taufik , Ariestya Gilang , Giriansyah Bayu
Published: October 2019

Hydrocarbon identification in mature fields located in Mahakam area is very challenging due to thin and multi layers of reservoir geometry, wide range of water salinity in deltaic environment, depletion and water-rise phenomena in highly producing zones. There are numerous possible gas reservoirs which were dubious and not included in perforation targets due to poor quality sand or risk of water production which could jeopardize the entire well potential. These possible gas reservoirs need to be re-evaluated in order to add perforation targets portfolio in maintaining field production when less new wells drilled.

An integrated methodology has been continuously developed and calibrated to reduce uncertainty, hence elevate confidence level of fluid interpretation by combining the existing and recently developed techniques in Mahakam fields. The existing techniques are (1) Conventional Qualitative interpretation, (2) True-Wet Resistivity separation, and (3) Gas-Oil Volumes from simultaneous solution. The new developed techniques are (4) Swirr-SWT comparison, (5) Water Saturation Array Gradient with salinity, (6) AutoFluid resistivity specific cut-off, (7) Dual logs sliding average analysis, (8) Neutron Count Rate, (9) RT-GR cut-off, and (10) Gas Chromatograph dynamic baseline.

In collaboration between petrophysicist, development geologist & reservoir engineering, this new integrated fluid interpretation methodology has been applied to re-evaluate more than 11,000 possible gas reservoirs in Mahakam fields. This effort has revealed around 32% of them as hydrocarbon potential reservoirs with total thickness of 4,195 meters. Those reservoirs are then convincingly re-interpreted as gas bearing reservoirs and included as additional perforation candidates. Some of those reservoirs have been perforated and giving additional gain in maintaining gas production of Mahakam fields.

By capitalizing the existing data, with no additional data acquisition, hence no additional cost, this integrated fluid interpretation methodology, could be implemented in other fields outside Mahakam to find hidden potentials which not identified yet.
Geochemical Modeling of Low Salinity Water Flooding EOR Mechanism
Authors: Chen Quan , Enezi Sultan , Yousef Ali
Published: October 2019

Low salinity water flooding (LSWF) is a cost-effective EOR technique. However, the underlining mechanism of LSWF EOR is still a matter of debate due to the complexity of the Crude Oil/Brine/Rock (COBR) system. The objective of this paper is to study the mechanisms of LSWF EOR processes by means of geochemical modeling.

A reactive transport geochemical modelling approach with a geochemical simulator PHREEQC (pH-REdox-EQuilibrium in C programing language) is applied in this paper to handle complex interplay of different geochemical effects such as ion exchange, rock mineral dissolution, flow and transport during LSWF EOR processes.

This paper proposes and demonstrates a geochemical mechanism for LSWF EOR, i.e., spreading of mineral dissolution waves driven by cation exchange process.

The sandstone reservoirs often contain clays and carbonate cements. Clay minerals are present in some carbonate reservoirs. LSWF disturbs the geochemical equilibrium between connate brine and rock minerals in the reservoirs and results in carbonate dissolution. This study shows that without the presence of clay minerals, carbonate mineral dissolution can only occurs locally close to the inlet of core plug or injection well in the field during LSWF and then new equilibrium between brine and rock minerals is reached. Because of the presence of clay minerals and the nature of cation exchange process, clay surface even more preferentially absorbs divalent cations over mono valiant cations during LSWF. This cation exchange process softens the injected low salinity brine and propagates the softened low salinity brine and therefore carbonate mineral dissolution waves from injection well to production well in the field. The spreading of carbonate mineral dissolution waves and the resulting local pH rise have several field wide consequences: (1) The carbonate mineral dissolution and the resulting local pH increase can occur field wide. (2) Mineral dissolution not only releases oil attached to the mineral surfaces but also creates more fresh water-wet rock surfaces and improves oil recovery of LSWF. (3) Rising pH makes both rock surfaces and acid components of crude oil more negatively charged. The subsequent electrostatic interactions help release of polar components from rock surfaces, and increase the water wetness of the rock surface and therefore improve oil recovery.
Success Story of Sustaining Production of Shallow Sand Reservoir with Screenless Fracpack Treatment in Mangunjaya Field
Authors: Putranti Andretiana , Yudis I Putu , Nasution Sakti Lail , Wijaya Rio , Giansyah Mohammad Zuly , Sarwono ArdhitoWirawan , Dusyanto Erwin Dicky
Published: October 2019

The wells in Mangunjaya field are known for high basic sediment (BS) production (more than 0.5%) and the need for frequent well interventions to cleanout formation sand production. A Screenless Fracpack operation was recommended as a solution for optimizing oil production by means of either the lifetime of the well or the maximum tolerance of BS% to reduce well intervention costs.

Four of the producing oil wells in the Mangunjaya field were treated with Screenless Fracpack treatment in 2018 as part of a well production maintenance process. This was not only to sustain oil production with the least possible intervention, but to reduce the basic sediment percentage to the range of 0.2 to 0.3% where it could be effectively lifted by beam pump and/or PCP pump.

The wells were producing from the Palembang Sand Formation with a total perforation interval of 3 - 17 m per well. The bottomhole pressure and temperature of the Palembang Sand Formation were 257 - 301 psi and 108.5 - 121°F. This formation is a shallow sand with the depth of the formation of 200 - 350 meters (TVD) and the formation has good permeability reservoir in the range of 50 - 300 mD.

The job size of the Screenless Fracpack was 30.3 to 37.7 Klbs (34.4 Klbs average) with a resin concentration of 3.75 gal per 1,000 lbm of ceramic proppant. The pumping rate was 12 to 16 bbl/min with surface pumping pressure of 500 to 1,000 psi. The wells were shut-in for 1 – 2 days to let the gel break and to let the resin cure.

Before the Screenless Fracpack treatment, the well production lifetime was around 90 days with two times well intervention with hoist (to cleanout the sand and repair the pump), the wells were producing 20 - 55 BOPD with more than 0.5% BS average. After the Screenless Fracpack treatment, the production lifetime increased. The wells were producing for more than 120 days with zero well intervention and production increased from 61 to 95 BOPD with 0.2 to 0.3 BS% lifted at higher rev/min of beam pump or PCP pump. This means that oil production was increased by 11 to 375% while the BS% was decreased by 33 to 93%.
First Application of Ultrasonic Technology in South East Asia: Breakthrough Case Study in Field T - Opening Doors for Alternative Stimulation Methods
Authors: Chang Claire Li , Spenger Oliver , Amran Amierul , M Khalil M Idraki , M Ariffin M Hafizi , Balakrishnan Dinesh
Published: October 2019

When a well has been diagnosed with formation damage, the norm is for operators to propose reservoir stimulation via acid/solvent pumping. In Field T, located offshore Bintulu in Malaysia, mineralogy understanding is limited as cores available only represent a few reservoirs. For those reservoirs which do not possess representative cores, it is a risk to prescribe any chemical. Historically, acid and solvent stimulation do not hold a good track record in T field. Hence, it is essential seek other stimulation methods that do not involve the requirement for mineralogy.

The UST (ultrasonic stimulation) technology operates on the concept of ultrasonic waves combined with low frequency waves breaking nearby damage up to 1000m into the reservoir. The resonator is conveyed by E-line, hence, possessing a smaller footprint as compared to mobilization of a pumping unit and chemical tanks. Platforms in Field T are small, hence, bringing a pumping package onboard will require hiring a barge due to limited deck space. Seemingly, operational risks are reduced as there is no need for manual chemical handling. The selling point of this technology is minimal well downtime as the stimulation can be performed on a live well, which further reduces possibility of damaging formation during stimulation due to secondary chemical reactions.

UST was piloted on 2 wells in Field T: Well X and Y. Well X showed an initial 30% gain post stimulation. Well Y was showing signs of clogged gas lift valves. Post operation observed pressure communication between tubing and casing which suggests that UST successfully broke the wax that was clogging the gas lift valves. A takeback from this project would be to not only stimulate the target reservoir, but to also stimulate the tubing walls and gas lift valves if there are any suspected valve plugging in the well. This paper will describe the technology that was used to stimulate the well in an environmentally friendly, non-invasive method. For fields with limited mineralogy data and deck space, it is recommended to explore an alternative stimulation method, such as UST, on the wells.
Modeling Interwell Interference: A Study of the Effects of Parent Well Depletion on Asymmetric Fracture Propagation in Child Wells
Authors: Guo Xuyang , Ma Junxiu , Wang Song , Zhu Tao , Jin Yan
Published: October 2019

Interwell interference has been widely observed in the development of unconventional reservoirs. It describes the phenomenon that legacy production of parent wells impact the completion quality of child wells, which in return changes production performance of both parent and child wells. This work models pressure and stress evolutions caused by parent well depletion and the corresponding asymmetric child well hydraulic fracture growth.

The study presents a 3D finite-element-based fully coupled flow and geomechanics model that simulates the poroelastic behaviors of pressure and in-situ stress evolutions, and a hydraulic fracture model. Based on the simulated pressure and stress heterogeneities at and around child wells, the complex and asymmetric fracture patterns for the child well can be quantified. In the study, with several candidate child-well locations placed away from the parent well, the stress and pressure evolutions along the child well are observed to be asymmetric. Numerical investigations show that production timing of parent wells, in-situ stress contrast, well spacing, parent well fracture geometry, and the design of perforation clusters along the child wellbore are key parameters affecting the asymmetric fracturing of child wells. Specifically, prolonged parent well production, small in-situ stress contrast and close parent-child well spacing lead to significant asymmetric stress and pressure evolutions along the child well, and consequently contribute to the asymmetric fracture wing growth during child well completion. Effects of the parent-well fracture geometry on asymmetric child-well fracture wing growth are only noticeable when the well spacing is small. This work identifies key parameters in a typical interwell interference case and studies their effects on asymmetric child well fracturing. The work serves as a reference for the avoidance of child-well underperformance, which is widely observed in many major shale plays.