bluuebunny/crossref_metadata_2025_split huggingface dataset:
Controls on dolomitization in extensional basins: An example from the Derbyshire Platform, U.K.
Authors: Breislin Catherine , Crowley Stephen , Banks Vanessa J. , Marshall Jim D. , Millar Ian L. , Riding James B. , Hollis Cathy 
Published: November 2020

ABSTRACTFault-controlled dolomitization has been documented in Lower Carboniferous (Viséan) platform carbonates at various localities in the Pennine Basin and North Wales. The largest of these dolomite bodies (approx. 60 km2) occurs on the Derbyshire Platform, on the southern margin of the Pennine Basin. This study tests the hypothesis that dolomitization occurred at this locality during deposition, platform drowning, and the earliest stages of burial, coincident with the transition from a late syn-rift to post-rift regime. It also assesses the importance of syn-rift volcanism on dolomitization. Planar, fabric-retentive dolomite with single-phase (i.e., low temperature) fluid inclusions occurs along NW–SE and E–W oriented faults, and in platform margin facies and in proximity to the Masson Hill Volcanic Complex. Oxygen isotope data are consistent with dolomitization from seawater, but slightly depleted δ13C values reflect mixing with magmatic fluids. Volcanic activity is likely to have produced a thermal drive for fluid circulation on the platform margin, and post-depositional alteration of basalts by CO2-rich fluids could have led to alteration of olivine and release of magnesium to convecting seawater. Consequently, the large volume of dolostone on the southern margin of the Derbyshire Platform is attributed to the increased geothermal gradient and a localized increase in the Mg/Ca ratio of dolomitizing fluids at this locality, compared to elsewhere in the Pennine Basin. The results suggest that syn-rift carbonate platforms in volcanically active areas of rift basins have a greater potential for dolomitization from seawater than non-volcanic platforms in the same basin.
Assessment of Supercritical Injection of Co2 Using Huff-N-Puff Approach in a Complex Reservoir Environment-SPE-202209-MS
Authors: Alali Zainab , Pardo Tacha Cesar , Oluwa Jubril 
Published: November 2020

Abstract
Carbon dioxide (CO2) injection at supercritical conditions using the huff-n-puff process has been proven to be an effective resource to mitigate the production impairment generated by near wellbore condensate banking in rich gas condensate fields. This approach decreases the density of condensate and at the same time increases the density of the gas, thereby generating a reduction in the interfacial tension between the two co-existing phases. This study evaluates the impact of CO2 injection under the huff-and-puff process on gas recovery enhancement using reservoir simulation.
A compositional reservoir simulator was utilized to perform CO2 injection at supercritical conditions. Several sector models with local grid refinement (LGR) were constructed to evaluate the impact of CO2 injection at supercritical conditions (huff-n-puff) on the condensate banking in wells with rich gas condensate production. The evaluation considered numerous scenarios of injecting supercritical CO2 at different decreasing reservoir pressures in combination with sensitivities of CO2 injected volume, gas production rate, and soaking time duration.
The results indicated a significant reduction of condensate saturation around the wellbore leading to improvements in gas productivity. In addition, an optimum CO2 injection frequency required to maintain low condensate saturation in the near wellbore region was established. Overall, the results indicated that injecting CO2 at supercritical conditions in carbonate reservoirs has the potential to mitigate the condensate banking problem. A positive correlation between reservoir depletion status and gas recovery was also established from the study: optimum treatment results are obtained at condensate saturation above 20%, and at reservoir pressures below the dew point.
Condensate banking around the wellbore can significantly limit gas/condensate production and recovery. The injection of CO2 to overcome this problem has been more commonly used on sandstones while its use on carbonates is still under testing and development. This paper presents a reservoir simulation study using huff-n-puff CO2 injection in a carbonate reservoir to enhance well production and mitigate condensate formation around the wellbore region.
Simplified Front End Loading: A Route to Better Project Outcomes
Authors: Newman David , Begg Steve , Welsh Matthew 
Published: November 2020

Abstract
This paper aims to encourage Front End Loading (FEL) to be used more effectively to increase the likelihood of delivering better project outcomes. It introduces a simple and pragmatic approach to assessing FEL which can be carried out in-house.
Previous research has shown that, despite FEL being highly regarded, companies regularly sanction projects with insufficient levels of FEL. This has frequently resulted in projects not achieving the outcomes promised at the Final Investment Decision (FID) in terms of cost, time and production attained. This paper reviews reasons why FEL may not be used very effectively at present and proposes a solution to change this.
An alternative method of assessing FEL has been developed which: is decision-based; can be carried out internally; and provides clarity on the factors that drive good FEL. In addition to assessing the status of activities carried out in the phase, the decision-based approach emphasises value-creation by considering key factors that could influence an increase or decrease in Decision Quality and thus the value created by the final outcome.
The benchmarking and the decision-based approaches to FEL are very different. FEL benchmarking is external, objective, more bottom up; whereas the decision-based approach is internal, subjective and more top down. The benchmarking approach is more detailed, with a large number of individual activities assessed, and the progress on these aggregated to provide an overall benchmarking score. The decision-based approach is more of a big picture view.
FEL benchmarking is well proven and its use is advocated. The decision-based FEL approach is unproven, but it has benefits that are not available from benchmarking and avoids some of the disadvantages. It encourages consideration to be given to activities that may result in value being created or destroyed; e.g. ensuring there are sufficient and appropriate alternatives during the Select phase, and that the benefits of flexibility are taken into account. A further advantage of the decision-based approach is that working through the FEL tools as a project team leads to a better joint understanding of the project and improves team integration.
The two approaches consider FEL from different perspectives and have different benefits. They complement each other, and so the combination of the two approaches is more powerful than either on its own. It is suggested that the two approaches are worked in conjunction with each other to gain the benefits of both methods, provide a better understanding of FEL, and have a stronger basis for decision-making.
A new way of assessing FEL has been developed which uses a decision-based approach aimed at increasing the value of project outcomes. Separate tools are provided for the Concept Select and FID phases.
Fracture-Matrix Modelling of CO2 Enhanced Shale Gas Recovery in Compressible Shale
Authors: Berawala Dhruvit Satishchandra , Østebø Andersen Pål 
Published: November 2020

Abstract
With the current technology, only 3-10% of gas from tight shale is recovered economically through natural depletion, demonstrating a significant potential for enhanced shale gas recovery (ESGR). Experimental studies have demonstrated that shale kerogen/organic matter has a higher adsorption affinity for CO2 than methane, CH4. CO2 is preferentially adsorbed over CH4 with a ratio of up to 5:1. This paper examines CO2-ESGR in compressible shale during huff-and-puff injection to better understand the parameters controlling its feasibility and effectiveness. A mathematical model will be presented where the CO2-CH4 substitution mechanism is implemented in an injection-production setting representative of field implementation.
A single hydraulic fracture surrounded symmetrically by a shale matrix will be considered. During primary depletion, gas is produced from the shale to the fracture by pressure driven flow and gas desorption. The porosity and permeability of matrix reduces due to compressibility. Stopping production and then injecting CO2 through the fracture and into the shale leads to increase in pressure, causing both the preferential adsorption of CO2 over CH4 and the restoration of porosity and permeability. The shale matrix then releases more CH4 in favor of the more chemically sorptive CO2. Restarting production from the well then allows more CH4 gas to be produced. Experimental adsorption data were used to quantify the substitution parameters while typical field data were used for the operating and geometrical conditions. Additional investigated production mechanisms include gas diffusion and changes in apparent permeability and porosity due to compressibility (addressed in Section 2.3.2).
Through a series of simulations, it was found that for the example studied, diffusion contributes the most to the performance of CO2-ESGR. Compressibility significantly reduces the matrix porosity and permeability during primary depletion, giving a positive effect to gas recovery. During CO2 injection, matrix porosity and permeability mostly recovers depending on pressure increase in the reservoir. The gas production seemed little sensitive to fracture permeability. The pore radius, the diffusion coefficient and the rock compressibility, parameters related to flow in the matrix, all affected the performance of CO2-ESGR.
Forced Oil-Water Emulsion to Tackle Flow Assurance Issues in Heavy Oil Reservoir
Authors: Sajjad Farasdaq Muchibus , Nugroho Wisnu Agus , Chandra Steven , Panaiputra Harris Grenaldi , Nurlita Dian , Towidjojo Reynaldo Billy , Rahmawati Silvya Dewi , Vico Hendro , Wirawan Alvin 
Published: November 2020

Abstract
Flow assurance has been a major problem in the development of a heavy oil field. It is not common that this issue has a multiplier effect from reservoir up to processing facilities, reducing productivity and in turn, increasing financial burden. Many of oil and gas operators in Indonesia have spent a lot of capital to deal with managing complex reservoirs with severe flow assurance issues, namely high water cut, excessively viscous oil and its effect on fluid flow.
Y Field has been produced for thirty years and currently produces 2800 BOPD with fluctuations in flow rate. This field is characterized by extreme oil viscosity, up to 4000 cP at surface condition, which leads to high backpressure while delivering fluid to pipeline system. This viscous oil creates unstable flow, causing unfavorable flow-pattern; slug flow to annular flow. As a result, the water and oil are not coherently arrived at the same time at receiving facilities, leading to highly frequent occurrence of oil-water slug phenomenon. Chemical injection efforts do not show significant impact toward the production, therefore an alternative approach is generated to address the production problem.
A new approach is presented in this publication to reduce the occurrence of severe slugging phenomenon by performing water blending scheme during fluid transportation. The idea is based on a hypothesis that performing forced emulsion of brine and heavy oil promotes dispersion of oil into small droplets which can be carried out by injected water under relatively low velocity of fluid flow. This idea is quite interesting since it is simple to perform, by only directing produced water from water zones below hydrocarbon bearing zone or by reactivating high water cut wells to the pipeline system.
In order to increase the efficiency of forced emulsion process, we approximated the minimum acceptable water cut to develop sufficient emulsion viscosity to prevent exceeding backpressure. Based on simulation using commercial software, the result shows that water cut should be maintained above 80%. A lower water cut will lead to high backpressure which will delay arrival time of oil for more than one day behind the water arrival. This result infers that one of the available solutions to handle severe slugging is by modifying water cut profile during hydrocarbon transportation. This approach gives a new insight into marginal field optimization.
Next Generation Ceramic Sand Screens as Open Hole Completion Solution in High Rate Erosive and Corrosive Well Environment at Dvalin HPHT Field, Offshore Norway
Authors: Ritschel Robert , Storhaug Jens , Dahle Bjorn Olav , Meschke Frank , Barth Peter , Jackson Steven Richard , Gundemoni Bhargava Ram , Danielsen Trond Helge 
Published: November 2020

Abstract
The Dvalin gas field is located in the Norwegian sea on NCS and is operated by Wintershall DEA Norge. It is supported by two independent reservoir structures, Dvalin East and Dvalin West. The field was explored through wells 14S and 15S in 2010 and 2012, respectively. The field is characterized by dry gas, high CO2, high temperature (160 °C) and high pressure (SIWHP 620 bar). The targeted Garn sandstone has good reservoir quality, but with a high permeability contrast.
The field development was sanctioned in 2016 and calls for a 4 well solution through a centrally located subsea template, producing gas back to the host platform Heidrun TLP 15 km away. Water depth at location is 380 m and targeted reservoirs are at 4140 m MSL (East) and 4240 m MSL (West).
Production plateau rates are estimated to be approximately 106 MMscf/D (3 million std m3/d) per well where thin high-permeability zones within the Garn formation are expected to dominate the inflow. The lateral facies development is thought to be relatively homogenous throughout the field, thus S-shape wells falling off to vertical through the reservoir will ensure effective drainage.
Sand failure is expected after short time of production and would increase the risk of erosion causing severe damage to well jewelry and production facilities. It has been decided to integrate sand screens as a means of downhole sand control as part of the primary lower completion design. The sand screens will offer sand control, erosion resistance, hot spotting resistance as well as robustness towards a full hole collapse during reservoir pressure depletion. As the subsea completions are carried out from a mobile drilling unit in harsh environments, protection of the sand control filter media during installation is of utmost importance.
This paper will describe the selection process of sand control and qualification steps carried out to use ceramic screens as the stand-alone screen solution for successful deployment and integrity for the Dvalin field development
Transforming the Mindset to Drill Ultra ERD Wells With High Tortuosity
Authors: Goodin Barry , Selman Duane , Wroth Andy , Singam Chandrasekhar Kirthi , Wang Haifeng , Viandante Mauro , Cardozo Nieto Manuel Felipe , Liu Yang 
Published: November 2020

Abstract
This paper describes the extensive integrated engineering collaboration and optimization process to allow the operator to push the drilling and completion envelope to drill complex ultra extended reach drilling (ERD) wells in a mature field. The Wandoo field is located within WA-14L in the Carnarvon Basin, offshore Western Australia and is wholly owned and operated by Vermilion Oil & Gas Australia Pty Ltd (VOGA). Due to the shallow reservoir depth, extreme ERD profile and the high tortuosity requirement for the wells, significant challenges were identified during the planning stages of the campaign.
To optimize well placement, update geological information and reduce collision risk with nearby producing wells, the Reservoir Mapping While Drilling (RMWD) service was run in real-time. The primary objective of the service was to place the well in the optimum position within the reservoir, this included (1) provide early detection of moved oil water contact (MOWC) while approaching well crossings with minimum separation factor to reduce collision risk and geological uncertainties; (2) to steer azimuthally to optimize the placement of the well with respect to the field bounding fault and reduce the drilling risk associated with the intersection of the fault; and (3) to distinguish between the A3 Upper (A3U), A3 Lower (A3L), and B sands to optimize well placement.
These challenges were successfully overcome with extensive planning, integrated engineering designs, application of new state-of-the-art technology, good quality real-time data interpretation and a strong execution support from both rig site and town.
As the result of good collaborative teamwork in planning and execution, the two highly technically challenging wells were drilled and completed successfully and brought online for production. A number of drilling performance highlights captured during the execution phase were identified as having significantly contributed to the successful completion of the project.
CO2 And H2S Co-Removal From Natural Gas Using Membrane Contactor Technology
Authors: Mohd Tamidi Athirah , Yasin Nor Hafizah 
Published: November 2020

Abstract
Acid gas removal mainly CO2 and H2S from natural gas is an essential treatment process in the oil and gas industry to increase the heating value of sales gas, prevent corrosion of pipeline and process equipment’s and avoid crystallization during the liquefaction process (Ahmad et al., 2010). Among the popular acid gas removal technologies, the amine-based acid gas absorption process that relies on chemical absorption of acid gas into aqueous amine solution followed by thermal regeneration is one of the technologies that is widely used in the oil and gas industry for acid gas treatment (Brau et al., 2017; Yu et al., 2012; Tay et al., 2017). For amine-based acid gas removal technology, contactors play an important role to ensure efficient and economical separation processes. Membrane contactor technology is one of the promising alternatives to existing conventional contactors that provides a large surface area per unit volume, independent gas and liquid flow rate and ease of scale-up for the acid gas absorption process. In this study, the feasibility of using membrane contactor technology for CO2 and H2S co-removal at high pressure was investigated. The effect of operating parameters such as gas flow rate, liquid flow rate and amine concentration on CO2 and H2S removal performance using activated MDEA as liquid absorbent was conducted using the design of experiment approach. Results from experimental runs have shown that the H2S target outlet which is ≤50 ppm was achieved at all operating conditions but not for CO2 outlet. The target CO2 outlet which is 6.5 mol% was only achieved at experimental runs where the condition of gas flowrate is the lowest, liquid flowrate is the highest and amine concentration is the lowest. The results achieved have proven that there is a high potential to use membrane contactor technology for co-removal of CO2 and H2S from natural gas.
An Improved Methodology to Derive Optimal Steady-State Oil-Water Relative Permeability Relationships: Concurrent Deployment of the 2-Phase Modified Carman-Kozeny and the Modified Brooks-Corey Formulations
Authors: Behrenbruch Peter , Quoc Doan Truc , Triet Do Huu Minh , Duy Bui Khang , Kennaird Tony 
Published: November 2020

Abstract
A detailed comparison is made of the more recently developed phenomenological 2-phase Modified Carman-Kozeny (2pMCK) relative permeability formulation with that of the industry standard, the Modified Brooks-Corey (MBC) formulation. The purpose is to show the strengths and weaknesses of the two formulations and to demonstrate how their combined use can yield the most consistent overall result, the optimum choice as input to reservoir simulation.
A brief overview of the two relative permeability formulations is given first. Several laboratory data sets are reviewed by deploying the two models, validating the data and pinpointing potential problems. In some cases, both methods are used to extrapolate lab results to determine a more realistic residual oil saturation value and corresponding water relative permeability endpoint, particularly for samples involving fines movement. The apparent increased degree of curvature of the oil relative permeability is also often problematic and is typically related to pore-fill, requiring modification to laboratory defined relationships. A clear workflow is outlined on how to derive overall optimal results. Both methods show that if additional information such as independent wettability measurements are available, there is more confidence in final relationships derived. As evident, problems are typically associated with the second data point and the final one, start and finish of multi-phase flow measurements, necessitating adjustment in oil relative permeability curvature and the final endpoint data, residual oil saturation and associated water relative permeability. If the curvature of the oil relative permeability is excessive, MBC extrapolation is prone to failure. While the 2pMCK model does not show such shortcoming, the model cannot currently handle very large exponents. However, for most realistic situations, such limitation is not a problem. Another advantage of the 2pMCK model is its ability to pinpoint laboratory artefacts.
The concurrent use of the two relative permeability formulations gives a new perspective of relative permeability modelling and is particularly suitable for quality checking and analysing more challenging laboratory results. The approach has been computerised, allowing for ease of data handling, model comparison and consistency.