bluuebunny/crossref_metadata_2025_split huggingface dataset:
Investigation of Barrier Water Injection at Gas-Oil Contact as Co-Development Plan for Gas Cap Reservoirs
Authors: Sharif Ahmed 
Published: November 2018

Abstract
A numerical simulation study was conducted to explore feasibility of gas cap and oil column co-development plans. Unlike conventional development schemes that entail to optimally produce first from oil column while deferring gas cap development, the co-development strategy studied here involves simultaneous production from oil column and gas cap. The drive mechanism consists of down-dip peripheral water injection for oil column in conjunction with barrier water injection at or near gas-oil contact that is designed to separate the gas cap from the oil column and thereby facilitate gas production. The basic objective of the study is twofold: to assess the merits of the concept of barrier water injection and to identify key subsurface and operational parameters that have most significant impact on oil and gas recovery. Extensive numerical simulations were conducted to explore the conditions under which the concept of barrier water injection is favourable as a recovery process. Important issues related to the viability of the development concept are how fast a barrier water can be established, how long it can be sustained and how many wells are needed. Furthermore, effects of gas cap relative size, reservoir geometry (e.g., dip-angle and surface area of the gas-oil contact), trapped gas, rock heterogeneity and off-take rates have been investigated in detail. The work shows that the feasibility of the co-development scheme is mainly controlled by pressure maintenance and balance of injection, relative size of gas cap, reservoir geometry and rock heterogeneity.
Chasing Middle Cretaceous Stratigraphic Traps in Offshore Abu Dhabi by Incorporating 3D Seismic Data into Machine Learning Methodology
Authors: Caeiro Maria Helena , Neves Fernando , Taher Ahmed 
Published: November 2018

Abstract
The aim of this study is to explore the Middle Cretaceous hydrocarbon potential particularly associated with prograding units. A machine learning based methodology is applied to evaluate the exploration potential of the Cretaceous Mishrif clinoforms in offshore Abu Dhabi, where a recent high-quality 3D seismic data have been acquired. The exploration objectives are to perform structural interpretation of the play; to infer reservoir quality, such as porosity; and to characterize the internal geometry of the reservoir and its seismic lithofacies.
Machine learning is a branch of artificial intelligence (AI) that plays a crucial role for evaluating data and building knowledge. In the context of subsurface characterization, the integration of AI into hydrocarbon exploration brings a substantial value for appraising different plays in a faster, robust and reliable manner. This is especially relevant in early exploration stages, when the availability of well data is limited but huge amount of high quality seismic data exist. Advantages of applying machine learning algorithms are its capability (1) to deal with several types of information and large 3D seismic data; (2) to learn by themselves from these data; and (3) to assist in interwell pre-drill estimates and associated uncertainties in a semi-automated context.
Seismic inversion is a process that integrates both 3D seismic and well data to derive reservoir properties. The seismic derived elastic models can be incorporated in reservoir modelling stage as secondary data, indicating the variability of the properties where there is no well information. Moreover, assessing the uncertainty related to reservoir quality of the Mishrif play will allow more effective exploration decisions, such as well placement and volumetric estimations.
Clinoforms depositional surfaces are identified in the seismic inverted elastic models, displaying lateral variation in geometry and reservoir properties. Given the high correlation achieved between acoustic impedance and log-porosity, it is infer with relative high confidence that better porosity development is expected to be found at the topmost part of the clinoforms. The quality of the reservoir is anticipated to degrade towards the edge of the clinoforms. Hydrocarbon charge model from the nearby Shilaif source rock kitchens will be incorporated to reduce the risk of future exploration activities in the area.
Optimal Thermowell Design Improves Plant Safety & Integrity
Authors: Ganesan Sankara Subramanian 
Published: November 2018

Abstract
The intent of this paper is to highlight the enhancements in latest Performance Test Codes (ASME PTC 19.3), evaluate the causes of failures occurred in thermowells and define the importance of optimal thermowell design.
Failure of a thermowell can have catastrophic consequences, which results in loss of containment and affects the plant safety, integrity & profitability. Hence, an efficient design, the proper selection and the operation within limits are essential to achieve 100% HSE and ensure a fit-for-future service.
Collaborative Approach to Bit Development for Drilling Abrasive Formations in Browse Basin
Authors: Edge David , Sadawarte Sagar , Shepherd Aaron , Spoljaric Hrvoje 
Published: November 2018

Abstract
A development programme offshore Western Australia required near horizontal 8.1/2" wellbores to be drilled through challenging formations. The hole section intersected sand-shale interlayers, referred to as the Tiger Sands, which is an abrasive formation with unconfined compressive strength (UCS)between 15,000psi and 20,000psi, with maximum UCS recorded up to 30,000psi. Underlying the Tiger Sands is the well cemented, abrasive Brewster sandstone with average UCS of 15,000psi and maximum UCS recorded up to 21,000psi, which has demonstrated a propensity to natural fractures. These challenges resulted in poor bit durability, low rate of penetration (ROP), difficult directional control,excessive shocks and downhole vibrations and significant downhole mud losses. The complexity of the drilling conditions required a systematic approach to be employed to optimise the poly-diamond crystalline (PDC) drill bit solution in order to improve durability and optimise ROP while successfully managing directional control, losses and ultimate drilling cost through the interval.
In addition to drill log analysis, after operations reviews (AORs) provided a comprehensive summary of operations from a rig perspective. These summaries were then used by the onshore engineering team to work in collaboration with the service sompany engineering team to develop a bit optimisation strategy. The first development well of the campaign was drilled with a standard 8 bladed 13mm PDC bit.
Natural fractures were penetrated and a total of ~4,500bbl of synthetic sased sud (SBM) was lost to the formation. The bit suffered impact damage and, therefore, had reduced durability. To solve thisproblem, a systematic approach was followed to gradually introduce improved design elements. Bit design progressed from cutter design, improved technology and ultimately, the introduction of new PDC cutter technology to record the fastest on bottom ROP for the drilling campaign of 10.32m/hr. Improved ROP and optimisation of the loss treatment strategy, allowed drilling operations to continue with minimal exposure to losses when present. Positive AOR feedback and continuous development from the service company resulted in further improvements to the PDC bit design with the introduction of ridged diamond elements and the latest generation conical elements to further improve steerability and ROP.
Continued developments resulted in New Design 4 being run in well 10. The entire interval was drilled in one run with excellent steerability and an overall 159% improvement in ROP equating to a reduction in drilling time by 5 days going from the original 813 PDC to the final New Design 4. In addition to ROP improvements, losses did not prove prohibitive to reaching TD due to drilling efficiency. Subsequent further improvements in ROP have been realized, with the entire interval drilled at 16m/hr.
PWHT Requirement for Submarine Pipelines Challenges and Way Forward
Authors: Singh Nawin , Kulshrestha Manoj , Nair Sajith 
Published: November 2018

Abstract
The objective of this study is to assess the provision of Post Weld Heat Treatment (PWHT) of girth weld on C-Mn steel submarine pipelines and propose an alternative to avoid PWHT. As per prevailing industry practice, the majority of the existing submarine pipelines handling sour service fluid, limit the steel grade to 450 MPa SMYS (X65). Such limitations on steel grade for sour service application results in high wall thickness especially for high pressure pipelines. This necessitates stress relieving requirements and hence leads to an uneconomical scenario for the project. Performing PWHT for girth weld of submarine pipelines is neither practical nor a cost- effective solution for the project.
The stress relieving requirement of girth weld is linked with pipeline wall thickness and such limitations on thickness varies based on selected governing design code for the submarine pipeline system.
ASME Pipelines Code has exempted PWHT to 32 mm of pipe wall thickness and such a limit is quite often surpassed for large diameter high pressure gas pipelines designed using Grade X65 steel.
To eliminate the need for impractical (in most cases) and expensive offshore PWHT, available alternate options include use of higher strength steel of grade X70 or above. However, in certain cases even higher steel grades do not help in elimination of the stress relieving requirement. Performing PWHT may further result in restricting the larger diameter (i.e. seam welded) pipe material to non-TMCP (Thermo Mechanically Controlled Processing). In such cases, necessary engineering analysis as per the provisions of pipeline design code needs to be performed. This paper discusses a systematic approach based on the provisions made in the Design Standards for waiver of PWHT, with further detailed engineering assessment based on fracture mechanics. A case study has been discussed the feasibility of PWHT waiver.
This paper will address the current limitation of using a higher grade of steel (e.g. X70, X80, etc.) for sour service and submarine applications. Provisions made in Design Standards for waiver of PWHT shall be evaluated by demonstrating an alternate method using fracture mechanics duly supplemented with engineering assessment.
Results from the case study substantiated by detailed engineering critically assessment (ECA) show that the acceptance criteria can be achieved without the requirement of PWHT. The mechanical properties of weldment are also acceptable without having stress relieving of the pipeline girth weld. A suitable methodology is discussed and presented to adopt in case such scenario arises for designing the submarine pipeline system.
De-Risking Chemical EOR Application in the Sabriyah Lower Burgan Reservoir through the Design of a Large-Scale Field Application
Authors: Al-Ghnemi Mohammad , Ozkan Erdal , Al-Murayri Mohammed , Pitts Malcolm , Dean Elio 
Published: November 2018

Abstract
The Sabriyah Lower Burgan (SALB) is a multi-billion-barrel reservoir located in north of Kuwait with favorable fluid and rock properties, with the addition of a strong active aquifer. The presence of the aquifer is favorable for primary development of the field but is a challenge for chemical EOR. The objective of this study is to identify the key challenges to be managed to increase the probability of success for a large-scale field implementation. The SALB has passed multiple stages of the EOR process (technical screening, laboratory formulation design, SWCT, pilot design) and is currently in the implementation phase for chemical EOR pilot. This paper assumes that the pilot is successful and addresses larger scale implementation concerns. It discusses the necessity of a large-scale multi-well pilot to evaluate economic viability and considers the risks of large-scale chemical EOR implementation in Sabriyah Lower Burgan. Three challenges are documented as key risks that can jeopardize a large-scale field implementation: (1) EOR Chemical/water incompatibility with reservoir, (2) economic factors, and (3) geologic features such as the aquifer.
The key findings and conclusion of this paper is the use of Monte Carlo simulation on reservoir simulation and economic parameters to evaluate their impact on the success of the project and outline the main risk parameters.
Production Potential of Shilaif Formation in UAE Using an Integrated Reservoir Characterization Approach
Authors: Alzaabi Mohamed A. , Uzun llkay , Eker Erdinc , Kazemi Hossein , Ozkan Erdal 
Published: November 2018

Abstract
As a result of shale oil and gas production success in the United States, development of shale resources elsewhere around the world has gained great interest. In the Middle East, where much of the world's conventional reserves are located, huge investments have been deployed to evaluate the potential of shale reservoirs. In this paper, we present an integrated reservoir characterization study of Shilaif shale formation in the United Arab Emirates, which includes an assessment of the primary production from a test well using a multi-phase, dual-porosity model. We also evaluated enhancing production performance via improved well completion.
In characterizing Shilaif's unconventional shale reservoir potential, we developed an integrated plan and workflow that included gathering and assessing the geological, petrophysical, and production data from a horizontal exploration well. The data used in the workflow included well-logs, cores, completion information, and pressure transient and production data from the well. The analysis of pressure build-up data ensuing the rate-transient period provided an estimate of effective formation permeability, which is a unique aspect of this study because such tests are not routinely conducted in shale reservoirs. The hydraulic fracture stimulation had improved the effective permeability nearly two orders of magnitude compared to the matrix permeability from cores and well logs. For the ultimate assessment and future performance, we developed a multi-phase dual-porosity numerical model. The simulation model was used to history-match the production data of hydraulically fractured horizontal well in Shilaif formation and case studies were conducted to evaluate the production potential.
For future development plans, it was determined that decreasing the fracture spacing from 250 feet to 150 feet was not economically feasible because the incremental production was around eight percent during the first year of production. Nonetheless, the simulation model indicated that Shilaif's large shale reservoirs may be viable for future development targets in the Middle East arena.
Successful Implementation of Torque and Drag Management Techniques in High Departure Wells is the Key to Safely Reach Wells Planned Total Depth in Offshore Artificial Islands
Authors: Diaz Nerwing , Paila Phalgun , Kirby Cliff , Akl Bassam , Mahmoud Dalia , Al Kindi Rashid Khudaim , Kasem Youssef , Benygzer Mhammed , Haddad Mohamed , Leon Vicente 
Published: November 2018

Abstract
Directional drilling from artificial islands has become a common offshore practice in the United Arab Emirates, looking to minimize footprint while optimizing cost to reach maximum number of targets from a single location. This drilling practice brings some challenges such as torque and drag limitations, which is vital in order to safely reach wells total depth in well profiles with a high departure. The purpose of this paper is to discuss in detail the successful implementation of torque reduction techniques, focused on case histories from an artificial offshore island in the United Arab Emirates.
During the planning phase, Drilling Engineers estimate expected torque and drag for the different sections based on modeling and historical data, this process is key to assess the limitations and initiate the process of evaluating the different torque and drag reduction techniques to be implemented based on the application. The case histories presented in this paper show the successful implementation of proven torque and drag management techniques, such as; well profile optimization, torque reduction subs, deployment of lubricated mud, use of real-time directional data to minimize hole tortuosity, and deployment of Rotary Steerable Systems from top to bottom for improved hole quality.
There are different factors considered in the planning phase that make torque and drag management crucial, but drill pipes torque limitation was the main challenge to overcome in order to reach planned total depth in the case histories discussed in this paper. Wells trajectory and BHA optimization played an important role during the execution phase, as well as the deployment of lubricated mud and torque reduction subs which in conjunction provided an overall surface torque reduction of up to 28%.
The implementation of different torque and drag reduction methods are illustrated with the modeling results and actual drilling data collected during the drilling of these wells. Information and data discussed in this paper can serve as documentation to aid in the planning phase for wells with similar challenges.
Optimization of Gas Lift Throughout the Well Lifecycle in Unconventional Reservoirs
Authors: Ayoub Joseph , Gao Sunhua , Jin Bikai , Blakey Brian , Krishnamurthy Shalini , Thambynayagam Michael 
Published: November 2018

Abstract
Given the pronounced nature of production decline in shale reservoirs, an integrated reservoir-well model that can efficiently anticipate the changes in reservoir and lift parameters over time is required in order to maintain optimum performance. The solution presented in this paper uses a novel integrated reservoir-well model specifically tailored for unconventional reservoirs to calculate the system deliverability and optimize gas injection throughout the well life. The integrated model is deployed in the cloud. It enables automation of the above process and allows more valuable exploitation of oilfied sensors such as multiphase flowmeters and of process control equipment in digital oilfields.
The model calculates for each well, the oil rate versus gas injection rate at any time during the well lifecycle by simultaneous solution of the reservoir transient IPR and the wellbore model. The resulting gas demand displays the typical maximum oil production and corresponding maximum gas injection rate beyond which oil rates would decline. The derivative is then used to calculate the gas injection rates versus time that meet a specific predefined economic objective. Single-well and multi-well scenarios are investigated and the impact of gas supply limit is evaluated to illustrate the practical applicability of the solution. Examples illustrate how the gas allocation among the different wells is calculated to achieve the optimum impact. Comparison of the production when gas injection supply is unrestricted versus production results with restricted gas supply is made and results of staggered production are presented.
Improved Zonal Isolation Achieved with Novel Scrubbing Spacer Deployed in Saudi Arabia
Authors: Al Mutahr Ammar , Shine Joe , Taoutaou Salim , Bazuhair Mohammed , Al-Sahlawi Ziyad , Jaafari Ahmed 
Published: November 2018

Abstract
Zonal isolation is reliant on successful cement placement. Part of the key criteria to achieve zonal isolation includes effective mud removal and fluid displacement efficiencies. To meet the mud removal requirements, a spacer system promoting physical or mechanical scrubbing appears to increase the efficiency of filter cake removal. The spacer has been deployed in Saudi Arabian wells containing water- and oil-based mud systems. For any given application, this paper discusses advanced laboratory testing to obtain performance properties such spacer stability and spacer integrity while managing the downhole plugging risks. This paper will document examples demonstrating results the spacer performance including cement evaluation logs supporting the use for achieving similar cement placement objectives.
Miscibility Effects on Performance of Cyclic CO2 Injection in Hysteretic Tight Oil Reservoirs
Authors: Assef Yasaman , Pereira Almao Pedro , Pourafshary Peyman 
Published: November 2018

Abstract
Dependency of relative permeability on saturation path during cyclic CO2 injection (CCI) in various operational constraints affects the oil recovery in different ways. A compositional reservoir sector model is built based on the available production data of hydraulically fractured horizontal well in Bakken formation. The work discusses the simulation results of the CCI and investigates the contributions of non-wetting phase's relative permeability hysteresis in oil production below and above the minimum miscibility pressure (MMP).
A CMG-GEM model is built based on the Bakken geological settings, well production and live oil PVT data. Relative permeability hysteresis model is incorporated within the simulator using the Killough's method. A cyclic CO2 injection (CCI) EOR scheme is designed and implemented in the numerical model. Effects of structural trapping and hysteresis-induced CO2 /gas retardation on oil recovery are studied during CCI in which a strong flow reversals may occur.
The results of simulation revealed that in non-hysteretic model, performing cyclic CO2 injection at immiscible (2000psi) and miscible (5000psi) conditions increases the recovery up to 12.8% and 22.64% respectively. Recovered oil after inclusion of relative permeability hysteresis demonstrate major corresponding effects of gas retardation, CO2 trapping and improved water permeability. The results show mole fraction of CO2 invading the reservoir remains constant at miscible condition and is not affected by hysteresis. Yet in hysteretic model, the oil recovery factor is slightly declined as the relative permeability to water is improved. The immiscible-hysteretic model incorporates high residual gas/ CO2 gas saturation at the end of each production (imbibition) cycle which increases gradually with historical gas saturation. CO2 mole fractions in both gas and oil phases are intensely decreased due to hysteresis following by decline in CO2 injectivity. Residual CO2 trapped during early cycles, limits the CO2 extent in reservoir and makes the recovery less efficient. In addition to residual saturation, oil composition varies due to different rates of vaporization and diffusion by CO2 as a result of its uneven distribution in reservoir.
We accurately evaluated the efficiency of cyclic CO2 injection in to Bakken tight oil reservoir by incorporating gas-trapping mechanisms in the model. Shortcomings of uncertainties associated with the previous simplified non-hysteretic reservoir models is reduced. Various operational conditions are tested. Our results draw a distinction amongst underlying mechanisms of recovery induced by hysteresis at different miscibility conditions.