bluuebunny/crossref_metadata_2025 huggingface dataset:
Delivering More Fit-for-Purpose Wells with Low Cost Approach at Untapped Area Matured Field – Application of Cone Concept Statistical Approach
Authors: M. Yusof M. Hatta , Sulaiman M. Zarkashi , A. Halim Rahimah , Ahmad Fauzi Nurfaridah , Sella Thurai Ahgheelan , Mahictin Masseera , Tg Yahya Tg Zuhaili , Muslim Fadli Adlan
Published: March 2021

This paper discusses the Case study of Field A in offshore Sarawak, Malaysia which focus on re-thinking development based on statistical analysis of the fields. Conventionally, well design is driven by subsurface requirement by targeting the high-reserve sand and well is designed to meet subsurface objectives. However, the conventional way may not be efficient to develop matured field environment due to the high CAPEX and the inconsistencies among well design especially in current volatile oil price period. The objective of this fit-for-purpose approach which is called "Cone Concept Statistical Approach" is to steer away from the conventional way of targeting only sweet spots whilst leaving the remaining potential resources undeveloped. Based on the statistical analysis and subsurface fields pattern, the "Cone Concept Statistical Approach" in which standardizing well design and trajectories was developed to extract the whole fields’ reserve at maximum. Well design boundaries were introduced to ensure this approach can be replicated throughout the field. Not only this study covers drilling perspective, completion perspective was also taken into consideration by exploring a cheaper and fit for purpose sand control method, considering it is a matured field with relatively short remaining field life. The Well Cost Catalogue for this field-specific approach was also developed which contains different types of design and completion, in order to holistically evaluate sand control method and identify the best option for the project moving forward.

This "Cone Concept Statistical Approach" aims to enable operator to drill simple wells within the same allocated budget in which poses low-to-no risk in the design and execution phase. This promotes a learning curve to improve operation & HSE, and ultimately gets positive project economics. Since this simple approach can be implemented early on even during the pre-FEL stage, the FDP team & host authority can come together to jointly discuss the targets/platform ranking and segregate them into various phases. Hence, the number of platforms or drilling centers, and its location also can be optimized early on with this concept, and again, translating into further reduction in overall project cost. This paper will help other operators and host authority to understand better on how a specific development concept on statistical approach can result and turn the matured-challenging fields into more economically attractive projects – low overall development cost and maximizing the recovery.
A Dynamic Workflow of Well Health Issue Prediction – Sulfur Deposition
Authors: Haq Bashirul
Published: March 2021

Sour gas reservoirs are vital sources for natural gas production. Sulphur deposition in the reservoir reduces a considerable amount of gas production due to permeability reduction. Consequently, well health monitoring and early prediction of Sulphur deposition are crucial for effective gas production from a sour gas reservoir. Dynamic gas material balance analysis is a useful technique in calculating gas initially in place utilizing the flowing wellhead or bottom hole pressures and rates during the well's lifetime. The approach did not apply to monitor a producing gas's health well and detect Sulphur deposition. This work aims to (i) modify dynamic gas material balance equation by adding the Sulphur deposition term, (ii) build a model to predict and validate the issue utilizing the modified equation.

A unique form of the flowing material balance is developed by including Sulphur residue term. The curve fitting tool and modified flowing gas material balance are applied to predict well-expected behaviour. The variation between expected and actual performance indicates the health issue of a well.

Initial, individual components of the model are tested. Then the model is validated with the known values. The workflow is applied to active gas field and correctly detected the health issue. The novel workflow can accurately predict Sulphur evidence. Besides,the workflow can notify the production engineers to take corrective measures about the subject.

Keywords: Sulfur deposition, Dynamic gas material balance analysis, Workflow
Personnel Real Time Tracking in Hazardous Areas Using Wearable Technologies and Machine Learning
Authors: AL-Qutami Tareq Aziz , Awis Fatin Awina
Published: March 2021

Real-time location information is essential in the hazardous process and construction areas for safety and emergency management, security, search and rescue, and even productivity tracking. It's also crucial during pandemics such as the COVID-19 pandemic for contact tracing to isolate those who came to the proximity of infected individuals. While global positioning systems (GPS), can address the demand for location awareness in outdoor environments, another accurate location estimation technology for indoor environments where GPS doesn't perform well is required.

This paper presents the development and deployment of an end-to-end cost-effective real-time personnel location system suitable for both indoor and outdoor hazardous and safe areas. It leverages on facility wireless communication systems, wearable technologies such as smart helmets and wearable tags, and machine learning. Personnel carries the client device which collects location-related information and sends it to the localization algorithm in the cloud. When the personnel moves, the tracking dashboard shows client location in real-time.

The proposed localization algorithm relies on wireless signal fingerprinting and machine learning algorithms to estimate the location. The machine learning algorithm is a mix of clustering and classification that was designed to scale well with bigger target areas and is suitable for cloud deployment.

The system was tested in both office and industrial process environments using consumer-grade handphones and intrinsically safe wearable devices. It achieved an average distance error of less than 2 meters in 3D space.
Integrating PVT, Stable Isotope and Biomarker Geochemistry and Pressure Data to Characterise the Continuity of a Geologically Complex Gas Condensate Reservoir
Authors: Bestman Somiari , Ghassal Bandar.I. I , Attar Ahmed , Kabir Akim
Published: March 2021

Characterizing reservoir continuity is a critical part of the field appraisal and delineation process and it carries an inherent risk for all stakeholders as well as significant implications for field development planning. The risk becomes even more substantial when planning the development of a geologically complex marginal field. Uncertainty and risk analyses are carried out in order to assess the potential impact of various parameters including geological uncertainties. However, the efficacy of the uncertainty and risk analyses processes are dictated by the quality and quantity of the available data. Thorough and extensive data collection and analysis, incorporating channels such as insitu reservoir fluid sampling, reservoir fluid characterization, molecular geochemistry, stable isotope geochemistry as well as pressure data will improve the outcomes of the uncertainty and risk analyses while minimizing reservoir continuity mischaracterization risks.
Challenges and Solutions for Conductor Sharing Technology with Higher Specification Conductor to Meet Target Fatigue Life
Authors: Khor Guan Han , Razali Ezuan Hanafi , Musa M. Idham , Mat Isa Saifol Anuar , Wan Hasan Wan Helmi , Chang Daryl
Published: March 2021

Since Conductor Sharing Technology became prominent in the 1990s, the technology has evolved to accommodate the associated well design and construction complexities. In the redevelopment of Brownfield "S", under an alliance between PETRONAS Carigali and other operator, the technology has enabled the number of potential new wells to be increased. However, the technology has been constrained in terms of the available conductor and casing size options. The objective is to advance the current technology to meet the well design and construction requirements.

This paper presents the challenges and solutions for conductor sharing technology to accommodate a higher specification conductor (36"×1.5" wall thickness), which is required to meet the fatigue life requirement in Field "S" Phase 3 redevelopment project. Since mid-2018, when PETRONAS took over the operatorship, further conductor analyses have been required. These studies confirmed the requirement for 36" conductor with 1.5" wall thickness, to meet the target fatigue life of 20 years. This paper focuses on a range of key engineering considerations related to well construction including geometrical separation, integration between CWD (casing while drilling) and directional, cementing, and diverter requirement to CWD surface casing.

Since there is no existing system that can accommodate this wall thickness and still be able to meet the well construction requirements, a collaboration with the equipment provider has led to the design and manufacture of the world's first splitter wellhead system used for 36" (1.5" WT) × 13-3/8"(2X) × 9-5/8"(2X) × 3-1/2"(4X) with 10,000 psi working pressure rating. The splitter wellhead has allowed two infill wells to be drilled and completed on Platform "A". The system has maximized oil recovery with the additional well. The successful installation and production from this wellhead provide opportunity to reduce construction cost and maximize utilization of existing well slots for future development of brown fields.

The improved technology has created more value by allowing surface casing to be installed by CWD in directional sections and the cementing program to be enhanced under diverter system. This solution will be beneficial to similar brown fields which have limited remaining slots and where it is unjustifiable to construct a new platform. In addition, it provides opportunity to lower the wellhead platform cost for green fields by optimizing the number of well slots and platform design.
Maximising the Value of Multi-Sensor Streamer Data via MAZ Processing
Authors: Zhang Hui , Yao Jianfeng , Li Xiang , Zhao Kai
Published: March 2021

The North West Shelf of Australia contains a late Paleozoic to Cenozoic sedimentary succession, which attains a thickness of over 10 km and is dominated by Triassic to Lower Cretaceous sediments. The deeper plays exist at multiple stratigraphic levels including oil-prone Jurassic sediments and faulted gas-prone Triassic sediments. The area has been proven difficult as far as seismic imaging is concerned, particularly over the Madeline trend. The presence of a hard, rugose water bottom, strong reflectors beneath the water bottom, and shallow Tertiary carbonates make the Dampier Sub-basin vulnerable to multiple contamination, amplitude distortion, lower signal-to-noise ratio (S/N) and unreliable AVO response. Poor seismic quality in the data has been a significant barrier to reducing exploration risk. In the 1990s, East Dampier (1992, blue polygon in Figure 1) and Keast (1997, yellow polygon in Figure 1) seismic data were acquired in East-West and North-South directions respectively, in an effort to better understand the impact from the shallow complex overburden. To address these challenges, the Demeter survey was acquired in 2003 (black polygon in Figure 1) with a denser acquisition grid. The overall seismic quality was improved, but the results still contained a significant level of residual multiples. Later, the Fortuna survey, the most comprehensive multi-sensor seismic survey on the North West Shelf of Australia to date, was acquired in 2014 with the aim to provide better subsurface imaging (pink polygon in Figure 1) from different acquisition perspectives. The data was processed with advanced processing technology, including shallow water demultiple, deghosting and high definition tilted orthorhombic velocity model building (Birdus et al., 2017). However, the final results were still suffering from a number of challenges, specifically: 1) strong residual multiple in near offsets, 2) low S/N ratio, particularly at reservoir level, and 3) inconsistency from near to far stack resulting in unreliable AVO.

In this paper, the Dixon area (green polygon), considered as the most challenging area in the Dampier Sub-basin, was chosen as the testing area for our work. By integrating high-end imaging technology, for example dual-sensor deghosting, multi-survey surface related multiple elimination (MAZ-SRME), and multi-azimuth processing (MAZ stack), we will illustrate how we have overcome many of these imaging challenges.
First Successful Installation of Through-Tubing Ceramic Sand Screen in Seligi Oil Field, Offshore Peninsular Malaysia
Authors: Kadir Masran , Rusli Muhammad Ruzwin , Samsudin Bukhari , Rahman Saim , Norizan Sheereen , Wee Thierry , M. Johan M. Alham , Al Zayani Sirag , Roslan Mohd Razeif , Mahadi Khairul Azmi , Salleh Muhammad Zulkhairi
Published: March 2021

The Seligi field, located 240 kilometers offshore peninsular Malaysia in the Malay basin was discovered in May 1971 and is one of the largest oil fields in Malaysia. Sand production in the Seligi field has been observed, especially from the J reservoirs group. Within the Seligi field, Well G was identified as one of the wells with sand production to surface that could lead to sand accumulation at surface facilities and erosion of equipment. Historically, there had been no in-situ sand control measures in the well. The default practice for sand control was to choke back the well, to prevent triggering of the surface sand probe (production with maximum sand-free rate). This approach however is a compromise, while it limits sand production, it also limits the production potential of the well (well technical potential). As part of the production enhancement assessment program, remedial sand-control methods were considered to increase the oil production while minimising sand production. Among the options considered was ceramic downhole sand screen installation. Ceramics have been used in many extreme erosion and corrosion applications, with ceramic sintered silicon carbide being 50 times harder than steel. Ceramic sand screens made with sintered silicon carbide offer much higher erosional resistance at speeds of 300ft/s sand impingement velocity. Due to the aggressive nature of the sands and high velocities of greater than 50ft/s in Well G, a through-tubing ceramic sand screen was selected. The ceramic sand screen served as a fit for purpose solution that allowed the well potential to be fully maximised, enabling a continuous production with minimal sand production at surface.

This paper reviews the first successful pilot installation of through-tubing ceramic sand screen in Well G in the Seligi Oil Field, Offshore Peninsular Malaysia. Discussed are careful analysis and planning, i.e. velocity calculations, tool deployment simulations, tool inspections and detailed job procedure leading to a successful installation. With the ceramic sand screen installed, the well was able to produce at 100% production choke opening with lower tubing head pressure and has not produced sand at surface despite multiple shutdowns and well bean ups. The installation has also removed the need to have sand handling facilities at topside and has generated an implicated cost saving from expensive intervention programs. Given the success of this pilot installation, a baseline in sand control has been set for this field, with new well candidates being considered for future replication.
Buried Strike-Slip Fault Identification Technique Based on a 3D Stress Body Attribute Considering Formation Deformation and Lithologic Variation
Authors: Wang Wei , Wu Kui , Kang Lin , Huang Xiaobo , Yao Jian
Published: March 2021

The identification and interpretation of buried strike-slip faults are of great significance int the search for structural traps in oil and gas exploration. However, it is difficult to identify and interpret buried strike-slip faults from seismic profiles and variance slicing, because they may be clear at depth but vague in the shallow. This study proposes a 3D stress body attribute taking into consideration formation deformation and lithologic variation to identify buried strike-slip faults. Taking into account thin plate theory and the generalized Hooke's law, a relationship between stress field, formation deformation and lithologic variation is established. Structural curvature body is used to represent the formation deformation, which is obtained by scanning of the body dip angle and second-order derivation of the wave number domain, while Poisson's ratio and Young's modulus volumes are employed to reflect the spatial lithologic variation, which are calculated by the multivariate linear fitting method or prestack inversion. This technique is applied to the secondary structural interpretation of JinZhou 25-1 oilfield in LiaoDong Bay depression of BoHai Bay Basin. Compared with the 2000 ms variance slice, it can be seen clearly that there is a significant stress concentration zone in the location of LiaoXi buried strike-slip fault from the 3D stress body attribute slice, which is consistent with a sudden change in strata observed on the profile. The LiaoXi buried strike-slip fault has been identified and interpreted. Many structural traps greater than 20km2 have been found along its course. Among them, W structure was drilled in 2016 and about 4.5 million tons of oil was found. This suggests that the spatial distribution of buried strike-slip faults associated with tectonics can be effectively identified through the strength property of the stress field, which is greatly superior to the conventional variance-related methods. It verifies the ability of this technique in the identification and interpretation of strike-slip faults in the entire Bohai Bay Basin and thus its potentially critical role in guiding secondary seismic interpretation.
Four-Dimensional Geological Modeling of Stress-Sensitive Reservoirs of Abnormally High-Pressure Carbonates
Authors: Chen Yefei , Li Kongchou , Ni Jun , Hou Qingying
Published: March 2021

The abnormally high-pressure carbonate dual-medium reservoir of the Kenkiyak Pre-salt oilfield in the littoral Caspian Basin has strong stress sensitivity. With the development of the oil field, the formation pressure drops and the fractures gradually close, resulting in a decrease of the effective permeability of the dual-media reservoir over time. So it is necessary to establish three-dimensional geological models of the dual-medium reservoirs at different times, which is the 4-D geological model.

Firstly, the reservoir matrix and fracture permeability model under the original conditions is established by using the dual-medium three-dimensional geological modeling method; Secondly, the formation pressure model for a given period is established by taking the measured well-point formation pressure in a certain period as hard data and combining with the formation pressure change trend in different zones; Thirdly, the carbonate reservoir types are identified by borehole imaging and conventional logging, and the geological model of the reservoir types in the original state is established. Finally, using the relationship between confining pressure and permeability reduction rate of different types of reservoirs obtained by core stress sensitivity experiments, and based on the original matrix and fracture permeability models, the matrix and fracture permeability models of different types of reservoirs at a given period are obtained.

Using the method proposed in this paper, the original matrix and fracture permeability model can be corrected to the matrix and fracture permeability model after the formation pressure drops at a certain period, and the 3D geological model of carbonate reservoir in any given periods can be obtained. Newly drilled wells at present confirmed that the geological model established by this method is reasonable and reliable. Taking the data of new wells completed during this period as hard data and the above three-dimensional geological model as soft data, an updated dual-medium model is established, which is more in line with geological reality. Based on the updated geological model, the deployment of oilfield adjustment schemes and well location optimization studies are carried out. The match between the new drilling data and the prediction results reached more than 90%.

The method solves the problem of updating the 3D geological model caused by the permeability change of the stress-sensitive reservoir, ensures that the geological model truly reflects the underground geological characteristics, and can be widely applied to the 3D geological modeling of stress-sensitive reservoirs.
Research and Application of Segmented Acid Fracturing Technology in Horizontal Wells of Ultra Deep Carbonate Gas Reservoirs in Southwest China
Authors: Wang Yang , Zhou Changlin , Zhang Huali , He Tingting , Tang Xinyuan , Peng Huan , Fang Hongming , Luo Le , Gang Shu
Published: March 2021

The Shuangyu gas reservoir in Southwest China is a fracture ultra deep carbonate gas reservoir. Its reservoir buried depth is more than 7000m, and the reservoir temperature is about 160°C. In the early stage, the vertical well acid fracturing method was used to obtain the natural gas production, but the gas production decreased rapidly after acid fracturing, which is difficult to achieve economic and efficient development. Segmented acid fracturing of horizontal wells is an effective way to greatly increase gas production. However, segmented acid fracturing of horizontal wells in Shuangyu ultra deep carbonate gas reservoir faces the following problems: (1)High reservoir temperature, fast acid rock reaction speed and short length of acid corrosion fracture. (2) The diameter of horizontal well is small (114.3mm), packer and other tools can not be put into the wellbore.

In this paper, through laboratory tests, an acid fracturing fluid with temperature resistance of 160 °C and friction resistance of 35% of water is developed. The fracturing fluid has the characteristics of high viscosity and high concentration of hydrogen ions, which can not only fracture the formation, but also carry out effective acid etching on the fracture during the injection process. Through the experiment, the temporary plugging agent which can meet the temperature of 160 °C and the combination of temporary plugging agent can form a sealing layer in the fracture with the width of 4mm, and the maximum sealing pressure can reach 20MPa. The research results have been successfully applied in well y616. After fracturing, the daily output of natural gas in well Y616 is 1 million cubic meters, which is more than three times that of the surrounding vertical wells.
Coring not Boring
Authors: Ashqar Ayham , Razak Amin , Ramly Noor Faezah , Dahlan Nur Athirah , Jamaludin Junirda , Karim M. Azan
Published: March 2021

Coring and core analysis are considered the only direct and physical data to provide a true reflect to the reservoir properties. The measured properties are used to calibrate subsurface models and ensures close to reality properties. Representative data is critical to allow achieving such target.

Coring planning and close follow up from the day decision is taken to core is important to achieve representative data.

The approach followed in this manuscript allowed a high probability of successful core cutting, and representative core analysis.

Field A is planned for appraisal phase and reservoir is expected to be of low permeability with sequence of shaly sands which adds complications to achieve the objective in cutting and analyzing the core. Different coring technologies were evaluated against the main coring objective of potential hydraulic fracturing field development. Conventional core is selected to offer the best value in both cost, and data coverage in compare to sidewall core. However, due to financial impact only one run was allowed, consequently it was critical to get the highest possible recovery and highest quality in one shot.

An extensive planning phase investigated all variables to ensure high recovery. Rock strength and its mechanical properties allowed the selection of optimum coring parameters, coring accessories, and coring bit. It is critical to the project to collect the core and the added challenge of only single run required detailed workflow. Borehole size, mud wt, rate of coring and coring parameters were challenging due to the given one time opportunity.

As a result, successful 100% core recovery is achieved, core retrieval to surface ensuring least core damage, this is demonstrated by CT scan which indicated no tripping out induced fractures. Well site core preservation reduced any weathering alteration, the selected stabilization method allowed minimal invasive to the core. Electrofacies guided by the whole core CT scans allowed the best coverage to the reservoir's properties. Long and large diameter plugs were achieved. Cleaning pilot study facilitated the selection of least damaging cleaning and drying method. Pilot small core analysis programs, and close follow up, and the analysis of raw data reduced the risk of unrepresentative core analysis results. Conventional core analysis data allowed refining and enhancing premeasurement electro facies and allowed a distinctive rock typing. The detailed planning permitted us to secure 100% core recovery and ensured core is reached the surface with least possible damage. The followed core analysis strategy reduced redundant experiments and allowed representative results at the same time optimized on the cost.

This paper demonstrates the best practice that is followed in challenging environment of shaly sand sequences to successfully cut core and develop a program, and workflow which reflects the uncertainties to be solved.
Cyclonic Separation Technology for Sand Management – Challenges and New Development
Authors: Shaffee Siti Nur , Che Daud M. Faizal , Myo Thant Maung Maung , Norpiah Rohaizad M.
Published: March 2021

Cyclonic devices are ubiquitous in industrial processes and have been used for particle separation for decades. However, designing a highly efficient, compact cyclone for erratic flow conditions and particles of varying types, sizes and density remains a challenge. This paper aims to present the challenges, lessons learnt and recent development in cyclone technology for solid separation.

Primarily, a discussion on typical cyclonic desander geometries is conducted. Failures and sub-optimal operation of cyclonic wellhead desanders within the company are analysed, and subsequently the failure mechanisms and factors leading to inefficiencies are identified. Computational Fluid Dynamics (CFD) simulations and flow loop testing are further performed to verify the particle separation efficiency and quantify the erosion risks of the typical cyclone geometries.

The typical cyclonic geometries are considerably less efficient in multiphase-flows compared to the gas-solid or liquid-solid flows. As a result, the overflow section of the cyclone often contains particles larger than the design specification. Changing operating envelope over time, for example, reducing production and changing flow regime affects cyclone efficiency over time. Based on a systematic analysis of the desander failures in the fields, a few design improvements have been proposed to overcome these limitations, resulting in a novel technology. This new cyclonic technology with multiple barrier system can successfully maintain the 98% target removal of 10microns particle under erratic multiphase-flows conditions. Furthermore, it can be designed to handle various types of particles e.g., sands, HgS and other solids. The versatility of this system provides promising technology for ageing fields with excessive solids production.
CoalBed Methane Pad Wells Completion and Artificial Lift Optimizations: Case Study From Australia Surat Basin DS Gas Field
Authors: Ming Li , Zhaohui Xia , Lingli Liu , Zehong Cui , LiJiang Duan , Jianjun Wang
Published: March 2021

The Coalbed Methane in Australia Surat Basin is main gas source for LNG project in east coast of Australia[1]. Traditionally, Coalbed Methane are drilled by vertical wells. But there are big intensively farmed land coverage in the Surat Basin, the multiple wells on single, larger pad from the surface, the bores slant away at around 70 degrees to intersect multiple, thin coal seams are applied to avoid the extra "footprint" and decrease the environment affect. Many pad wells production failure because of poor interburden isolation. Excessive solids production in pad wells resulted in new failures of holes in tubing due to accelerated erosion, which bring big challenges for the Coalbed methane production in deviated pad wells.

The gas production in pad wells are analysised and the new pad wells optimization are proposed. First, the complete wire log (at least include GR and density log curves) need to acquire for correct thin coal seams correlation and locate the interburden sandstone position for future good sandstone isolation. Second the customized completion strategy and placement (swell packer) are applied in the pad wells and specialized tubing with enhanced erosion resistance to extend the run life. Thirdly ESP pumps and optimized tubing are installed in new deviated wells for good gas production.

After the pad wells were put into production, the gas production was kept well for long time without pump problems. Swell able packer completion significantly eliminates sand problem by isolating in excess of or close to 80% of interburden sand.

The above well completion and artificial lift optimization methods bring good production performance for the new pad wells and contribute much production for the producing gas field. The swellable packer completion also can be used in vertical wells and will be standard well completion methods for future gas development wells.
Hybrid Physics-Field Data Approach Improves Prediction of ROP / Drilling Performance of Sharp and Worn PDC Bits
Authors: Zhan Guodong David , Magana-Mora Arturo , Moellendick Eric , Bomidi John , Huang Xu , Bird Marc
Published: March 2021

This study presents a hybrid approach that combines data-driven and physics models for worn and sharp drilling simulation of polycrystalline diamond compact (PDC) bit designs and field learning from limited downhole drilling data, worn state measurements, formation properties, and operating environment. The physics models include a drilling response model for cutting forces, worn or rubbing elements in the bit design. Decades of pressurized drilling and cutting experiments validated these models and constrained the physical behaviour while some coefficients are open for field model learning. This hybrid approach of drilling physics with data learning extends the laboratory results to application in the field. The field learning process included selecting runs in a well for which rock properties model was built. Downhole drilling measurements, known sharp bit design, and measured wear geometry were used for verification. The models derived from this collaborative study resulted in improved worn bit drilling response understanding, and quantitative prediction models, which are foundational frameworks for drilling and economics optimization.
The Dusk of MEFS in the Digital Era of Exploration Value Creation
Authors: Surovtsev Dmitry , Joshi Parth , Sethi Muhammad Usman
Published: March 2021

The concept of minimum economic field size (MEFS) has been used by explorationists for almost four decades. MEFS is often the only filter to distinguish between a commercial and a non-commercial discovery—far before a wildcat well is drilled—to test a prospect for a working petroleum systems hypothesis. As simple as it gets, the concept started to lose traction in the 21st century as subsurface targets became more and more challenging. In the case of tight hydrocarbons, it is fairly common to observe a P90 case net present value (NPV) to be negative, a P50 case to be positive, and a P10 case to be negative again. The reason for this outcome is that a whole set of full-cycle factors, in addition to the field size, affects prospect commerciality. Their uncertainty ranges can match or exceed resource estimate uncertainty. These factors include, but are not limited to, initial productivity of development wells, estimated eltimate recovery (EUR) per well, decline curve parameters, capital investments, operating costs, and the project phases’ durations.

A new way of handling the full universe of risks and uncertainties faced by modern explorers is already available in the new generation of industry-leading integrated prospect risk, resource and value assessment software. Innovators and thought leaders can already substitute MEFS with a commerciality threshold (CT) that neatly mimics board considerations at the final investment decision (FID) stage gate. Others can consider the economic chance of success (ECOS) estimated with a probabilistic full-cycle mindset, as an additional metric valuable for risk management purposes.

Using fictional case studies inspired by real-life assessment situations, we discuss the additional value creation by a CT-powered workflow as compared to an MEFS-based one and explain the reasons for the key differences.

The discussed workflow does not eliminate nature-specific uncertainties; neither does it reduce the geological risk. However, it helps to better understand human-controlled risks and prepare management exploration decisions with a greater degree of confidence.
TitleApplication of M4C P-wave and S-wave Joint Inversion in Shallow Reservoir Identification
Authors: Zhu Sian , Chen Hongtao , Hu Yongjun , Yang Feng , Feng Yubin
Published: March 2021

The genetic mechanism of shallow gas reservoirs is complex, which is usually characterized by shallow burial depth, multiple types, low reserves and wide distribution, so that the inversion based on P-wave data alone may be ambiguous. For shallow reservoir with large lateral variation, it is hard to accurately predict oil and water distribution by conventional P-wave prestack inversion. Marine four-component (M4C) P-wave and S-wave joint inversion can solve the problem effectively. M4C seismic survey collects P-wave and S-wave seismic data. An initial model can be established based on fine structural interpretation of P-wave and S-wave data and S-wave compression pattern matching. It lays a good foundation for subsequent P-wave and S-wave joint inversion. Based on the P-wave seismic record equation proposed by Fatti et al., a seismic record equation from poststack P-wave and S-wave joint inversion was derived according to the relationship among reflection coefficient, P-wave impedance, S-wave impedance and density, then important lithologic parameters (P-wave impedance, S-wave impedance and density) were calculated, and finally the ratio of P-wave velocity to S-wave velocity which is more sensitive to oil and gas was obtained. According to the ratio of P-wave velocity to S-wave velocity, the oil and gas distribution was predicted in shallow Bohai Bay Basin. Application has proven that the inversion can well reflect the fluid distribution, and the coincidence between the inversion results and the drilling data is up to 85%.M4C seismic survey was conducted for the first time to the shallow oil and gas reservoirs with rapid lateral variation in the Bohai Bay Basin, and collected raw P-wave and S-wave seismic data. Based on the data, the precision and reliability of P-wave and S-wave joint inversion was improved. The results provided strong technical support to the reserves and production increase in the Bohai Bay Basin.
Jumping on the Digitalization Bandwagon for BOP Pressure Testing
Authors: Lai Kheng Looi , Provan Martin , Abdullah Malik Faisal , Hoak Eric , Hoke Gabe
Published: March 2021

Blowout Preventer (BOP) is mainly used to control well pressure by quick well shut in the event of overflow and well kick to prevent blowout on the rigs during drilling, completion, workover, and plug and abandonment phases of well operations. Regulators, Operators and Drilling contractors have put in place the requirement to test BOP systems as a method of inspection and assurance in this process safety critical steps. During well operations regular BOP pressure testing will need to be conducted to ensure its integrity and functionality as per testing requirement. In most cases BOP pressure testing is conducted online using rig time although it can also be conducted offline in some circumstances.

BOP Pressure testing is considered flat time during well operations and the operators’ goal is to minimize flat times for rig time saving thus operating cost reduction. Flat time reduction can be achieved by reducing BOP pressure testing period and improving the efficiency in the entire testing process. As such a digital pressure testing system was deployed to multiple offshore drilling rigs in Malaysia beginning in September 2019 as innovative technological solutions.

This paper represents the digital pressure testing system deployment study on both subsea and surface BOP drilling rigs for direct comparison with the process in use of the analog circular charter recorders (CCR) for BOP Pressure Testing. The study has shown an average 22% reduction in test times, improved safety, improved efficiency in recognizing failed tests faster, improved data reliability and repeatability of BOP pressure tests.
FEP Based Model Development for Assessing Well Integrity Risk Related to CO2 Storage in Central Luconia Gas Fields in Sarawak
Authors: Patil Parimal A. , Chidambaram Prasanna , Bin Ebining Amir M Syafeeq , Tiwari Pankaj K. , Das Debasis P. , Picha Mahesh S. , B A Hamid M Khaidhir , Tewari Raj Deo
Published: March 2021

Underground storage of CO2 in depleted gas reservoirs is a greenhouse gas reduction technique that significantly reduces CO2 released into the atmosphere. Three major depleted gas reservoirs in Central Luconia gas field, located offshore Sarawak, possess good geological characteristics needed to ensure long-term security for CO2 stored deep underground. Long-term integrity of all the wells drilled in these gas fields must be ensured in order to successfully keep the CO2 stored for decades/centuries into the future. Well integrity is often defined as the ability to contain fluids without significant leakage through the project lifecycle.

In order to analyze the risk associated with all 38 drilled wells, that includes 11 plugged and abandoned (P&A) wells and 27 active wells, probabilistic risk assessment approach has been developed. This approach uses various leakage scenarios, that includes features, events, and processes (FEP). A P&A well in a depleted reservoir is a very complex system in order to assess the loss of containment as several scenarios and parameters associated to those scenarios are difficult to estimate. Based on the available data of P&A wells, a well has been selected for this study. All the barriers in the example well have been identified and properties associated with those barriers are defined in order to estimate the possible leakage pathways through the identified barriers within that well. Detailed mathematical models are provided for estimating CO2 leakage from reservoir to the surface through all possible leakage pathways.

Sensitivity analysis has been carried out for critical parameters such as cement permeability, and length of cement plug, in order to assess the containment ability of that well and understand its impact on overall well integrity. Sensitivity analysis shows that permeability of the cement in the annulus, and length of cement plug in the wellbore along with pressure differential can be used as critical set of parameters to assess the risk associated with all wells in these three fields.

Well integrity is defined as the ability of the composite system (cemented casings string) in the well to contain fluids without significant leakage from underground reservoir up to surface. It has been recognized as a key performance factor determining the viability of any CCS project. This is the first attempt in assessing Well Integrity risk related to CO2 storage in Central Luconia Gas Fields in Sarawak. The wells have been looked individually in order to make sure that integrity is maintained, and CO2 is contained underground for years to come.
Real-Time Quantification of Offshore Oil Spills During Blow-Out Accident
Authors: Chandra Steven , Sajjad Farasdaq
Published: March 2021

In the event of offshore oilfield blow-out, real-time quantification of both spilled volume, recovered oil and environmental damage is essential. It is due to costly recovery and restoration process. In order to develop a robust and accurate quantification, we need to consider numerous parameters, which are sometimes tricky to be identified and captured. In this work, we present a new modeling technique under uncertainty, which accommodates numerous parameters and interaction among them.

We begin the model by identifying possible parameters that contributes to the process: grouped into (1) subsurface, (2) surface and (3) operations. Subsurface e.g. well and reservoir characteristics. Surface e.g. ocean, wind, soil. (3) Operations e.g. oil spill treatment blow-out rate, oil characteristics, reservoir characteristics, ocean current speed, meteorological aspects, soil properties, and oil-spill treatment (oil booms and skimmers). We assign prior distribution for each parameter based on available data to capture the uncertainties.

Before progressing to uncertainty propagation, we construct objective response (amount of recovered oil) through mass conservation equation in data-driven and non-intrusive way, using design of experiment and regression-based method. We propagate uncertainties using Monte Carlo simulation approach, where the result is presented in a distribution form, summarized by P10, P50, and P90 values.

This work shows how to robustly calculate the amount of recovered oil under uncertainty in the event of offshore blow out. There are several notable challenges within the approach: 1) determining the uncertainty range in blow-out rate in case of rupture occurs in the well, 2) obtaining data for wind and ocean current speed since there is an interplay between local and global climate, and 3) accuracy of capturing the shoreline geometry. Despite the challenges, the results are in-line with the physics and several recorded blow-out cases.

Through sensitivity analysis with Sobol decomposition, we can define the heavy hitters. These heavy hitters give us knowledge on which parameters should be aware of. In real-time quantification, this analysis can provide an insight on what treatment method should be performed to efficiently recover the spill. We also highlight about the sufficiency of the model to obtain several parameters’ range, for example blow-out rate. The model should at least capture the physics in high details and incorporate multiple scenarios. In the case of blow-out rate, we extensively model the well completion and consider leaking due to unprecedented fractures or crater formation around the wellbore.

We introduce a new framework of modeling to perform real-time quantification of offshore oil spills. This framework allows inferring the causality of the process and illustrating the risk level.
Predictive Modelling of CO2 Injectivity Impairment due to Salt Precipitation and Fines Migration During Sequestration
Authors: Md Yusof Muhammad Aslam , Ibrahim Mohamad Arif , Mohamed Muhammad Azfar , Md Akhir Nur Asyraf , M Saaid Ismail , Ziaudin Ahamed Muhammad Nabil , Idris Ahmad Kamal , Awangku Matali Awangku Alizul
Published: March 2021

Recent studies indicated that reactive interactions between carbon dioxide (CO2), brine, and rock during CO2 sequestration can cause salt precipitation and fines migration. These mechanisms can severely impair the permeability of sandstone which directly affect the injectivity of supercritical CO2 (scCO2). Previous CO2 injectivity change models are ascribed by porosity change due to salt precipitation without considering the alteration contributed by the migration of particles. Therefore, this paper presents the application of response surface methodology to predict the CO2 injectivity change resulting from the combination of salt precipitation and fines migration. The impacts of independent and combined interactions between CO2, brine, and rock parameters were also evaluated by injecting scCO2 into brine saturated sandstone. The core samples were saturated with NaCl brine with salinity between 6,000 ppm to 100,000 ppm. The 0.1, 0.3, and 0.5 wt.% of different-sized hydrophilic silicon dioxide particles (0.005, 0.015, and 0.060 μm) were added to evaluate the effect of fines migration on CO2 injectivity alteration. The pressure drop profiles were recorded throughout the injection process and the CO2 injectivity alteration was represented by the ratio between the initial and final injectivity. The experimental results showed that brine salinity has a greater individual influence on permeability reduction as compared to the influence of particles (jamming ratio and particle concentration) and scCO2 injection flow rate. Moreover, the presence of both fines migration and salt precipitation during CO2 injection was also found to intensify the permeability reduction by 10%, and reaching up to threefold with increasing brine salinity and particle size. The most significant reductions in permeability were observed at higher brine salinities, as more salts are being precipitated out which, in turn, reduces the available pore spaces and leads to a higher jamming ratio. Thus, more particles were blocked and plugged especially at the slimmer pore throats. Based on comprehensive 45 core flooding experimental data, the newly developed model was able to capture a precise correlation between four input variables (brine salinity, injection flow rate, jamming ratio, and particle concentration) and CO2 injectivity changes. The relationship was also statistically validated with reported data from five case studies.