bluuebunny/crossref_metadata_2025_split huggingface dataset:
Oil Rim Development by Waterflooding: Lessons Learned from the South Turgai Basin Case Studies
Authors: Mukanov Adil 
Published: October 2022

Abstract
Characteristics of two brown oil fields in the South Turgai Basin Field pose challenges for field development. Oil rims bounded by a gas cap on one side and an aquifer on another side are present in both fields. These features coupled with poor rock properties make the development of these fields challenging. As a result, enhanced recovery techniques are necessary for the economic production of oil and gas.
Accounting for high saturation pressure and weak aquifer reservoir pressure maintenance is considered critical for the oil rims, as these have been observed twofold reduction in reservoir pressure from the initial one. To account for such effects, previous producing wells were converted to gas and water injection wells. Gas flooding of the gas cap is performed using a crestal injection pattern and water injection into the gas-oil zone is used to create a water bank between the gas cap and oil rim. Moreover, waterflooding is launched by peripheral water injection with additional advantages attained from gravity segregation.
Changes in oil and gas production have been observed as a result of pressure maintenance. First, the gas injection implemented in the wells located 1.5-3 km from the oil rim have prevented gas breakthrough in producers, despite the significant injection rates. High injection rates are a result of the governmental ban on flaring, since this prompts engineers to perform faster pressure recovery and target a higher volume of utilization. Second, crestal and edge water injection have different results in different parts of the fields. However, in some cases rim flooding have devastating effects as producers have been watered out. On one hand, the goal of decreasing the gas production was met, which happened earlier and was one of the biggest challenges facing the company. Consequently, gas-oil ratios decreased almost ten times than what they were previously. On the other hand, water-cut on many producers increased substantially, up to 90-95%, and in some areas top injectors even killed the down-dip producers. Thus, despite having solved one problem, another one emerged. Overall, crestal water injection (i.e., barrier waterflooding) is risky, and requires stricter regulation and management.
Case studies from the South-Turgai Basin show that water injection in top structure of oil rims for enhanced oil recovery can lead to positive as well as negative results. Overall, the paper demonstrates the cause-and-effect relationship of the previously described impacts of such water injection and provides recommendations for proper waterflooding management in oil rims based on the success in other parts of the field.
Case Study of Successful and Optimal Strategy to Test and Evaluate Three Target Reservoirs in Single Exploratory Well
Authors: Siddique Faisal Anwar , Aslam Muhammad Adeel , Khan Imran , Abbasi Yasir , Khan Zaid , Hasany Syed Tariq 
Published: October 2022

Abstract
A case history of an exploratory well in Lower Indus basin in Pakistan, is described where Massive Sand Deep, Massive Sand Shallow and Basal Sands of Cretaceous Lower Goru formation were target reservoirs, however, during drilling, positive indications were also observed in Sembar formation of early Cretaceous age.
Successful formation evaluation of three target reservoirs posed a great challenge, due to bad hole conditions and bad cement job. This resulted in risk of no formation zonal isolation between target reservoirs along with risk of operational issues due to high mud weight.
The strategy was adopted to test and conclude each reservoir with marginal potential, as such, other reservoir formation evaluations were not compromised. Decision tree based methodology was extensively used to convey the plan, which really proved helpful and avoided confusions for all shareholders and decision makers.
A thorough critical analysis of previous formation testing/Drill Stem Testing (DST) jobs and their success rates were performed. Analysis of cement logs, mud and wireline logs were performed to select best evaluation jobs for respective targets. Similarly for formation testing jobs, zones of interest needed further optimization considering zonal isolation and presence of cement behind pipe.
The testing strategy resulted in the best possible formation evaluation and finally conclusion of all three targets reservoirs. With this, cost optimization was achieved as all targets were tested in single well. Use of decision tree was successful in conveying status and way forward at each step, which avoided confusion in all shareholders. Also, as future way forward was already put in place in form of decision tree, based on encouraging/ disappointing results, everyone involved knew about the course of plan. Integration of all available technical data was very critical which helped maneuvering in taking decisions. The strategy became so successful, that shareholders advised to make it part of every new project.
This project presented and prompted company and joint venture partners, the valuable use of flow charts and decision trees and proved to be an excellent tool to convey information, to stay aligned and to be aware of future strategy.
Hydraulic Fracturing QA QC Indispensable to Delivering Both a Successful and Economic Fracture Program
Authors: Al Salmi Hussein , Al Shueili Ahmed , Jaboob Musallam , Al Qassabi Mohammed 
Published: October 2022

Abstract
It is well known that close quality assurance and quality control (QA/QC) are of vital importance for the successful placement of any hydraulic fracturing treatment. Many complex pieces of equipment and specialized personnel are involved in the fracturing process, and the following of strict QA/QC standards is mandatory to make these operations successful, efficient and safe. BP Oman is using massive hydraulic fracturing treatments to exploit the challenging tight-gas Barik Formation in the Khazzan and Ghazeer Fields. Each treatment is designed to place 1 million pounds of proppant into this tight, high pressure high temperature reservoir, leaving no space for error.
Implementing QA/QC and logistic supply measures begins with the mobilization procedures: chemicals checklist/verification and mixing on the base, timely equipment maintenance, bulk plant proppant delivery to ensure a swift and smooth 24 hour operation. Water delivery management loading quality check, logistics, site acceptance and minimum quality checks are another important procedure related to this preparation. Each fracturing stage requires at least 14,000 bbl of fresh water to be available and quality checked on the site before the start of the fracturing treatments. Intensive QA/QC measures continue through the day of the fracturing treatment itself to ensure the equipment is in full working condition. Assurance that all of the supply systems are properly calibrated, all chemicals loaded and levels physically measured. During the fracture treatment itself all parameters are repeatedly measured and visualized in real time. Fluid viscosity is assessed on the fly and data verified with an HPHT viscosimeter also present on the wellsite. After the treatment, all remaining chemicals are measured once again and carefully assessed against the expected inventory values and material balanced.
Implementing extensive QA/QC procedures enabled efficient mobilization between wells with mobilization time as low as 6 days despite the complex equipment and material needs for these massive fracturing treatments. Planned logistics and consistent quality checks before, during and after the treatment enabled BP Oman to successfully place more than 100 hydraulic fracturing stages with the amount of proppant exceeding 1 million pounds per stage. The bar has raised even higher with successful placement of 2 million pounds of proppant, the largest single stage hydraulic fracturing treatment in the Eastern hemisphere at the time of execution.
Optimization Experience on the Use of Carbon Steel Tubing for Sweet Corrosive Gas Field
Authors: Mitraningsih Farih , Styward Boris , Tokoh Kristoforus Widyas , Angela Irene 
Published: October 2022

Abstract
CRA 13%Cr has been used at all Mahakam swamp and offshore gas wells since 1990's for oil country tubular goods (OCTG) particularly for production tubing, due to its excellent CO2 corrosion resistance. By mid of 2000's, when depletion observed in one reservoir level, the new production started from different level, thus reduce the wells design life and increase the completion job frequency. To avoid completion delay due to tubing material delivery, CLAS 3%Cr and Carbon Steel (C-steel) tubing were proposed. By late 2010's, the study was done to develop materials selection guidelines to provide necessary information allowing early selection of the most appropriate and cost effective Steel for lower well completion. And finally, since 2015, C-steel tubing has been applied to all entire tubing (lower and upper completion a few hundred meter below safety valve) on sweet corrosive gas well through systematic corrosion and erosion assessment, which has been verified as well by tubing wall measurement logging. This paper summarizes the outcome of several studies has been done, and demonstrate the optimization on the use of C-steel tubing instead of higher grade material, as part of corrosion management strategy to synchronize fit for service and economical objective.
Applied Framework for Managing Sustainable Retrograde Gas Condensate Reservoirs
Authors: Tawfiq Rowa , Alahmadi Asma 
Published: October 2022

Abstract
Managing retrograde gas condensate reservoirs comes with its set of challenges. To maximize recovery and ensure the sustainability of reservoirs, the reservoir engineer must ensure the proper well placement, choose the best completion, and perform regular reservoir surveillance. This paper discusses an applied framework for managing retrograde gas condensate reservoirs, to ensure the longevity of the reservoir and maximize performance.
The process of managing sustainable retrograde gas condensate reservoirs entails proper well placement, which can be achieved through an in-depth assessment of the targeted geological formation in terms of reservoir development. This is further assessed through acoustic impedance maps, seismic data, and any reservoir modeling available. Also, choosing the correct completion of the well is a function of the information obtained from well logging and sampling. Finally, proper reservoir surveillance should be implemented after the well is put on production. Information such as pressure and temperature data, zonal production contributions, and pressure build-up tests should be obtained regularly.
Following proper well placement, correct completion choice, and regular reservoir surveillance can aid in maximizing production and ensure the sustainability and longevity of the reservoir. Utilizing a comprehensive geological model to study both the structure and development of the reservoir can aid in choosing the optimum well type: vertical, horizontal, or deviated, as well as the required completion. Once well logging and sampling are performed, an optimal completion method can be deployed. Typically, porous sandstone reservoirs require some sort of sanding control method to not impede the production of gas. Tight gas reservoirs would require fracking to increase permeability, and sand control to reduce sand production. As an alternative, tightness can also be overcome by drilling horizontal wells with high inclination to increase reservoir contact. Finally, reservoir surveillance is of utmost importance for retrograde gas condensate reservoirs. Reservoir fluid characterization aids in determining the dew point pressure, after which condensate starts to produce. Several methods are discussed to reduce the effect of condensate production.
This paper discusses a framework for managing a retrograde gas condensate reservoir, where successful planning, completion, and surveillance can be applied. The article also sets forth a flow chart to exemplify the optimum path to manage and sustain retrograde gas condensate reservoirs successfully.
Successful Intervention into a Six-Leg Multi-Lateral Well Using an Electrical MultiLateral Tool Deployed on Real-Time Hybrid Coiled Tubing for Acid Stimulation of a Kuwait Field - A Case Study
Authors: Bastaki Fahad , Al Matar Mohammed , Omar Mizan , Barki Jassim , Jamal Mariam , Al-Mutairi Fayez , El-Aziz Sabry , Albahar Zakaria , Al-Mehena Mehanna , Khandelwal Nakul , Chawla Sapna , Gaur Rishika , Alkreebani Mohammad , Travesso Joshua 
Published: October 2022

Abstract
Multilateral technology offers multiple benefits to oil and gas operators, including lowering the field development cost by minimizing wellsite construction work and increasing reservoir contact leading to enhanced reservoir production. To gain full advantage of these complex wells, they must be stimulated properly.
The operator in Kuwait drilled, cased, and cemented a six-leg, level IV multilateral well targeting two different formations, the upper and lower Tuba. This provided various production options and the flexibility of taking production from either the lower or upper laterals or even all six laterals to help mitigate the risks of drilling horizontal or directional wells. As such, multilateral technology can positively transform the economic viability of reserves in marginal fields. Exploiting the advantages of multilateral technology requires a multi-disciplinary approach to select appropriate well structure, completion design, re-entry flexibility, and production longevity.
Intervention in this level IV multilateral well presented several challenges, such as Oil Based Mud (OBM) in all the laterals, encountering a fault in one of the laterals while drilling, and high shale content that can lead to stuck Coiled Tubing (CT) and the loss of fluid returns. Real-time hybrid cable CT was chosen along with an electric multilateral tool to mitigate the various risks involved. This solution includes a hybrid fiber optic and electrical cable installed in the CT string and a modular Bottom Hole Assembly (BHA) equipped with various sensors. An electrically controlled indexing tool, inclination sensor, tool- face sensor, downhole camera, hydraulic knuckle joint, and pulsating stimulation tool were used as part of the BHA to enable real-time diagnostics and dynamic controls from the surface to successfully enter and stimulate all the lateral legs. This configuration helped identify each different lateral without the need to tag the bottom of each lateral. The paper focuses on applications, strategies, and benefits of specific tool configurations developed for multilateral well intervention, enabling the stimulation of all the lower Tuba laterals. This was a particularly challenging operation due to shale in one of the laterals causing several instances of stuck CT with the possibility of a collapsed hole mitigated by using the real-time camera in the BHA.
This paper includes strategies that address proper tool selection, confirmation of lateral entry, hydrostatic pressure balance, borehole stability, and acid design. It also explores the potential of new, synergistic strategies and work processes planned for stimulation of the upper Tuba field.
Time-Lapse Pulsed Neutron Logging Helps Maximize Recoveries from Mature Field - Case Study from Mangala Field of Rajasthan, India
Authors: Kumar Alok , Sigtia Shraddha , Das Joyjit , Guha Rupdip , Ahmed Abaan , Shankar Vivek , Kumar Suresh , Chauhan Nishi , Kumar Ravinder , Ramakrishna Sandeep 
Published: October 2022

Abstract
Mangala Oilfield of Rajasthan has produced over 36% of STOIIP and has been subjected to several innovative and new era technologies since it started producing in August’ 2009. Initially, field was under Water flood phase till April’2015 and then full field Polymer flood phase started to maximize recovery. Mangala field with medium-gravity viscous crude oil & formation water salinity of approximately 8000ppm has an excellent reservoir property of high porosity (24 to 26%), high permeability (200md- 20D) and very low irreducible saturation i.e., less than 5%. Thus, C/O logging in this field has been a very good choice to estimate the remaining oil saturation (ROS) and understand the sweep of oil due to injection which in turn has helped in maximizing recoveries from the field.
Time-lapse PNL were run in several wells to monitor the efficacy of the water flood/polymer flood phase on oil recovery. The objective was two-fold; to estimate the change in saturation over time and to identify by-passed or marginally swept intervals. The process begins with recording the initial saturation in the wells before any production has occurred. Then time-lapse data are recorded to monitor the change in saturations. Secondly, saturation estimation from PNL data were used to plan the next course of action- workover operations, changing completion zones, abandoning certain zones or wells, and infill drillings. PNL data in combination with other reservoir surveillance techniques (MPLT) has proved to be a vital surveillance tool to maximize the recovery from this field.
In this paper, we present the effectiveness of PNL tool specially RMT-I with production data over a period of 3 years (post Aug 2019). However, the results also include integration of other PNL dataset (RST & Raptor) acquired for reservoir surveillance activity and the challenges involved in interpreting the result of different PNL tool over time.
In absence of RMT 3D tool, PNL is acquired as 1 Sigma up/down pass and 3 CO up passes at 1fpm-3fpm to address the uncertainty related to gas presence on C/O interpretation. Sigma measurement helped in identifying gas below packer or in the annulus behind pipe and helped in addressing the uncertainty related to gas presence on C/O interpretation. Secondly, RMT was planned in infill well post drill to determine the uncertainty between OH and Cased hole Oil saturation. The results agreed with production data and uncertainty in oil saturation estimation was minimized to 10-15% approximately. Several cases will be discussed in the paper to demonstrate the use of PNL logs for reservoir management.
Generation of a Regional Fluid Database for Gas Condensate Assets in a Thrusted Carbonate Environment of the Northern Emirates
Authors: Saradva Harshil , Golaco Christna , Robert Matthew , Jain Siddharth , Callum Thurley , Bentaher Abdulhafid , Al Hamadi Masoud 
Published: October 2022

Abstract
Sharjah National Oil Corporation (SNOC) operates 4 onshore fields, the largest of which has been in production since the 1980's, in addition to over 50 years of exploration activity in the region. The producing fields exhibit a wide range of condensate-gas ratio (CGR) productivity and other properties. The scope of this paper is to discuss how the data from these exploration and development wells was combined to develop a trend of the fluid properties within the Northern Emirates to assist in the Future SNOC activities.
A detailed data scouting and processing workflow was undertaken and all available legacy pressure-volume-temperature (PVT) reports were digitized. All available separator recombined samples reports and bottomhole sample reports were compiled into a master database. The well test reports were thoroughly examined to understand the field operations and determine the reliability of the PVT reports while the fluid samples were collected during the well tests. An equation of state was generated for each field using all available information taking into account their production history over 30+ years and the results were then used for the regional PVT study.
A distinct trend of CGRs, specific gravity and other reservoir fluid properties were observed which co-related with the formations. These prospects which are spread out all over the Emirate of Sharjah were compared on the same parameters to develop a regional guideline. A regional trend of changing fluid properties was also observed which helps define the fluid properties expected in the Thamama Group formations in the Northern Emirates from any exploration well. The results will assist in determining the valuation of any exploration prospect if it is deemed successful and also plan ahead for the value of the prize. These trends also helped fill in missing data and perform quality control (QC) on older fields where comprehensive lab data was unavailable. In some cases, gas condensate fluid properties were unattainable at the mature stage of the field and this study provided the necessary information to plan enhanced recovery opportunities.
This paper aims to be a leading reference for the PVT fluid properties in the complex Thamama Group of the Northern Emirates to support future exploration and development activities. The regional data provides a strong correlation and this information is novel in terms of utilizing legacy data for potential opportunities. The new database also helps QC the dataset of existing PVT reports along with aiding in identifying the sources of hydrocarbon origin in this region.
Evolution of Well Completion Strategy in Deep High-Pressure Sour Environment to Enhance Rig-Less Operations & Optimize Rig Workover Operations
Authors: Al-Hajri Hamood , Al-Subhi Anees , Khayrutdinov Fanis , Al-Busaidi Asaad , Al-Shukaili Ibrahim , Al-Abri Humaid , Al-Abri Zahir , Al-Hadhrami Abdullah 
Published: October 2022

Abstract
Deep critically sour fields played a key role in PDO's production portfolio for past two decades particularly in the south of Oman. Cost-effective solutions to develop these fields was certainly needed to ensure that oil produced from these fields is economically attractive. Completion design optimization was successfully implemented leading to significant savings in life-time cost of these well.
Completion optimization journey was performed in stages based on the challenges encountered throughout the life of the field. Due to risky nature of the reservoirs in these fields, wells were completed with tubing and permanent packers to ensure well integrity requirements are fulfilled and all operation risks are controlled. These permanent packers induced a big challenge during well intervention & workover as they have low success chances when it comes to milling. This base completion design was optimized including eliminating the use of permanent packers to achieve savings of about 5% in well cost at least 80% in well interventions.
At early stage of the field life, combining drilling caprock and reservoir section and casing them with the same liner was considered as a good saving in well drilling cost leading to total cost reduction of about 5% of total cost. However, this optimization increased cost of well intervention dramatically in these wells as the tubing and packer need to be retrieved to gain full access. In addition, challenges in milling the permanent packer have increased intervention cost even further. This first optimization done was to introduce a liner across the reservoir section of the same size as the tubing (Mono-bore completion). This optimization made the completion more Rig-less friendly and reduced well intervention cost by at least 80%. The second optimization done was to replace the permanent packers with Tie-back Polished Bore Receptacle (PBR). This has eliminated the requirement for packer milling without jeopardizing the sealing functionality of the permanent packer. This design was even optimized further to eliminate the possibility of failure of the permanent packer or PBR by introducing cemented completion. Cemented completion has also reduced total cost of drilling & completing the wells by 5% while maintaining the advantage to perform well activities and minimum cost.
These improvements in well completion strategy have reduced life-time cost of the well dramatically without jeopardizing well basic functional requirements and well integrity requirement. As a result of this work, production from these field became more economically attractive.