bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Superior Shale Oil EOR Method for the Permian Basin
Authors: Downey Robert , Venepalli Kiran , Erdle Jim , Whitelock Morgan 
Published: September 2021

Abstract
The Permian Basin of west Texas is the largest and most prolific shale oil producing basin in the United States. Oil production from horizontal shale oil wells in the Permian Basin has grown from 5,000 BOPD in February, 2009 to 3.5 Million BOPD as of October, 2020, with 29,000 horizontal shale oil wells in production. The primary target for this horizontal shale oil development is the Wolfcamp shale. Oil production from these wells is characterized by high initial rates and steep declines. A few producers have begun testing EOR processes, specifically natural gas cyclic injection, or "Huff and Puff", with little information provided to date. Our objective is to introduce a novel EOR process that can greatly increase the production and recovery of oil from shale oil reservoirs, while reducing the cost per barrel of recovered oil.
A superior shale oil EOR method is proposed that utilizes a triplex pump to inject a solvent liquid into the shale oil reservoir, and an efficient method to recover the injectant at the surface, for storage and reinjection. The process is designed and integrated during operation using compositional reservoir simulation in order to optimize oil recovery. Compositional simulation modeling of a Wolfcamp D horizontal producing oil well was conducted to obtain a history match on oil, gas, and water production. The matched model was then utilized to evaluate the shale oil EOR method under a variety of operating conditions. The modeling indicates that for this particular well, incremental oil production of 500% over primary EUR may be achieved in the first five years of EOR operation, and more than 700% over primary EUR after 10 years. The method, which is patented, has numerous advantages over cyclic gas injection, such as much greater oil recovery, much better economics/lower cost per barrel, lower risk of interwell communication, use of far less horsepower and fuel, shorter injection time, longer production time, smaller injection volumes, scalability, faster implementation, precludes the need for artificial lift, elimination of the need to buy and sell injectant during each cycle, ability to optimize each cycle by integration with compositional reservoir simulation modeling, and lower emissions.
This superior shale oil EOR method has been modeled in the five major US shale oil plays, indicating large incremental oil recovery potential. The method is now being field tested to confirm reservoir simulation modeling projections. If implemented early in the life of a shale oil well, its application can slow the production decline rate, recover far more oil earlier and at lower cost, and extend the life of the well by several years, while precluding the need for artificial lift.
Enhancing Hydrocarbon Production Through Thermal Gas Injection from a Retrograde as Condensate Reservoir in the Western Desert in Egypt
Authors: Taha Maged Alaa , Shokier Eissa , Attia Attia , Yahia Aamer , Mansour Khaled 
Published: September 2021

Abstract
In retrograde gas condensate reservoirs, condensate blockage is a major reservoir damage problem, where liquid is dropped-out of natural gas, below dew-point pressure. Despite that most of this liquid will not produce due to not reaching the critical saturation, natural gas will be blocked by the accumulated liquid and will also not produce.
This work investigates the effects of gas injection (such as methane, carbon-dioxide, and nitrogen) and steam at high temperatures on one of the Egyptian retrograde gas condensate reservoirs. Several gas injection scenarios that comprise different combination of gas injection temperature, enthalpy, injection gas types (CO2, N2, and CH4), and injection-rates were carried out.
The results indicated that all conventional and thermal gas injection scenarios do not increase the cumulative gas production more than the depletion case. The non-thermal gas injection scenarios increased the cumulative condensate production by 8.6%. However, thermal CO2 injection increased the condensate production cumulative by 28.9%.
It was observed that thermal gas injection does not vaporize condensate It was observed that thermal gas injection does not vaporize condensate more than conventional injection that have the same reservoir pressure trend. However, thermal injection mainly improves the condensate mobility. Appropriately, thermal injection in retrograde reservoirs, is mostly applicable for depleted reservoirs when the largest amount of non-producible liquid is already dropped out. Finally, this research studied executing thermal gas injection in retrograde gas condensate reservoirs, operationally, by considering the following items: carbon dioxide recovery unit, compressors, storage-tanks, anti-corrosion pipe-lines and tubing-strings, and corrosion-inhibitors along with downhole gas heaters.
Computational Fluid Dynamics for Gas Lift Optimization in Highly Deviated Wells
Authors: Sajjad Farasdaq , Chandra Steven , Wirawan Alvin , Dewi Rahmawati Silvya , Santoso Michelle , Suganda Wingky 
Published: September 2021

Abstract
In the implementation of gas lift, understanding flow behavior in highly-deviated well is critical in avoiding production loss due to liquid fallback and blockage, even in highly-productive reservoir. In this work, we utilize Computational Fluid Dynamics (CFD) to optimize gas lift design under various flow behavior in highly-deviated well. The analysis is directly implemented into Arjuna offshore field case.
Arjuna offshore field has gas-lifted wells, producing from a high-permeability reservoir. However, several wells suffer from huge production loss due to the effect of well's deviation. In deviated well, there exists frequent liquid fallback causes blockage, therefore, reducing the production. Motivated by this issue, we use CFD framework to perform gas lift optimization.
We firstly adopt the geometry of gas-lifted wells as the computational domains for our simulation. An image-based meshing technique is deployed to capture the well's trajectory and internal geometry. We secondly utilize compressible Navier-Stokes equation and Finite Volume Method to evaluate the flow behavior. We capture the location of liquid fallback and liquid accumulation at elbows to estimate production loss. We consider the variation of viscosity, density, gas lift valve placement, injected gas rate, and reservoir pressure. We finally perform gradient-based optimization utilizing production loss as the objective function to obtain optimum design. The final result is then used to optimize the current design.
The simulation results show that productivity index, pipe diameter, and deviation heavily influence the amount of production loss. At big pipe diameter and high deviation, the gravitational force governs the fluid flow. Therefore, slugs are developed and accumulated at elbows. This accumulation blocks gas flow and reduces production.
Changing the gas injection rate affects the lifted density. High injection rate triggers segregation between the liquid and gas, while low injection rate does not reduce the liquid density. Shifting the gas lift valve placement influence the mixing between the liquid and gas. It also determines the cost of gas injection. Hence, we need to optimize both parameters at once.
Six of thirty wells in Arjuna field experience severe liquid fallback, therefore, the production significantly decreases. The simulation shows up to 40% coverage of the pipe internal diameter, which blocks the gas flow. We perform the optimization by shifting the gas lift valve placement and adjusting the gas injection rate. By implementing the study result into the field case, we manage to improve the production by 20%.
We provide an effective way to connect high-resolution simulation to the field design and revise the current concept in designing gas lift well completion. The simulation allows engineers to provide more insight on flow assurance in highly deviated wells.
The Innovative Integration of Wellbore Strengthening and Managed-Pressure Drilling Redraw the Line Between Undrillable and Drillable - Case Study from Offshore Mediterranean Deepwater
Authors: El-Husseiny Mahmoud , El-Fakharany Taher , Khaled Samir 
Published: September 2021

Abstract
Managed pressure drilling (MPD) has a reputation for enhancing drilling performance. However, in this study, we use it as a technology for making undrillable wells drillable.
In the deepwater of the Mediterranean of Egypt, a gas field has been producing for few years. Water broke through in one well, thus, we must drill a new well to compensate for the reduction in production. Years of production led to pressure depletion, which makes it difficult to drill this well conventionally.
In this study, we will discuss the combination of MPD and wellbore strengthening (WS). In addition, we will discuss the challenges we met while drilling and how we tackled them, and the best practices and recommendations for similar applications.
The 12¼" × 13½" hole section passed depleted sands, followed by a pressure ramp. First, we drilled the depleted sands and confirmed the pressure ramp top. To strengthen the sand, we spotted a stress-cage pill of 645 bbls with a total concentration of 29 ppb. In addition, we conducted a formation integrity test (FIT), but its value was lower than the required value to drill to the section target depth (TD). Then, we switched to MPD and increased the mud weight. MPD in annular pressure control mode (AP) enabled us to walk the edge as near as possible to the impossible. Drilling this section was challenging due to the narrow mud weight window (MWW). We faced kick-loss cycles, where we had high-gas levels (from 20% to 55%) while drilling with a loss rate from 60 to 255 bph, at the same time.
The 8½″ × 9½″ hole section will cover a depleted reservoir. Therefore, we decided to use the MPD to drill this section. To widen the MWW, we decided to stress-caging the hole, as we drill. We loaded the active-mud system with stress-cage materials totaling 39 ppb. We drilled the hole section while keeping the bottom hole pressure (BHP) at 14.6 ppg. We drilled using MPD by maintaining 525-psi surface back pressure (SBP). We used the SBP mode (semi-auto mode) to add connections, resulting in minor background gases and minor losses.
This study discusses the application of a novel combination of MPD and WS. It emphasizes how MPD can integrate with other technologies to offer a practical solution to future drilling challenges in deepwater-drilling environments.
Khuff and Pre-Khuff Reservoir Fracture Characterization using the Cross Dipole Shear Wave Imaging and Borehole Imaging Data Integration
Authors: Menon Pradeep , Swedan Tarek , Jan Kamran , Al-Shehhi M. S. , Kieduppatum Piyanuch , Bouzida Yasmina , Cazeneuve Adrian Eduardo , Zhunussova Gulzira , Uluyuz Sila , Telang Viraj 
Published: September 2021

Abstract
Increasing demands for gas in UAE have led to increased focus on more tight gas reservoirs like Khuff and pre-Khuff formations, away from the conventional oil-bearing carbonate reservoirs. The case study presented is in an offshore field, Northwest of Abu Dhabi city. The structure, with an area of 50 Sq.km was first identified in 1966 and it is part of the regional N-S extending structural.
The multi-discipline approach applied in this study required the integration of a suite of open-hole data over a variety of length scales. Combination of the Borehole Acoustic Reflection Imaging technique and borehole imaging logs (BHI) in 3D, provides a better understanding of the complex fracturing network and the associated formation stress orientation up to 100ft away from the wellbore. The ability to "see" away from wellbore what was previously hidden on seismic, allows unlocking further potential reserves or avoiding certain production hazards.
The well has penetrated the highly economical tight clastic Pre-khuff formation and the carbonate Kuff formation, allowing the analysis over a large geological history of offshore Abu Dhabi. The coherency of all data has helped establish for the first time a baseline understanding of the role of the fractures and fault in the petrophysical properties distribution along the wellbore and the 3D structural characterization in an larger area around the wellbore (up to 100ft).
The emphasize in this paper is on the Borehole Acoustic Reflection Imaging technique (DSWI), which allows the identification of both intersecting and non-intersecting of geological features with a depth of investigation up to 100 ft away from the borehole. Moreover, the combination of DSWI with BHI have been used for the anisotropy estimation away from wellbore especially in a very tight and fractured reservoir deciphering multiple fault orientation, which potentially, cancel the anisotropy estimation due to destructive interference. In addition to the presence of drilling induced fractures interfering in with the natural fracture as seen on the BHI.
The detailed BHI interpretation and the petrophysical data revealed that the fracture densities and orientation vary from bottom to top interval indicating tectonic regimes affecting the field. The lithological variation due to the evolution of the depositional setting has significantly influenced the fracture distribution and their length.
The presence of these induced fractures and how deep they propagate into the formation, dominates the behavior acoustic anisotropy by reaching the flexural (dipole shear) investigation zone (3 to 4ft deep). It is also interesting to see the behavior of both natural and induced fractures and their respective strike change over the different formations revealing a geomechanically complex structure.
Eliminating Diffusion Effects from NMR Logging Data for Enhanced Carbonate Pore Typing
Authors: Hursan Gabor , Shao Wei , Balliet Ron , Farooq Yasir 
Published: September 2021

Abstract
Transverse relaxation (T2) times measured by multi-frequency, multi-gradient nuclear magnetic resonance (NMR) logging tools are affected by diffusion-induced enhanced relaxation which reduces the sensitivity to pore size in slow-relaxing formations such as macroporous carbonates and complicates the integration with zero-gradient core NMR data. We propose a solution for eliminating the diffusion-related uncertainties using intrinsic T2 distributions, obtained by a new inversion-forward modeling-inversion (IFMI) method, for carbonate pore typing applications.
The NMR logs presented in this paper are based on data measured at five frequencies where the static magnetic field gradient varies from 26 to 55 G/cm. The high-quality echo signals are processed using a three-step IFMI differential signal analysis approach which nullifies diffusion effects due to the tool gradient and the potentially present internal gradient caused by paramagnetic minerals in the formation. The resulting diffusion-free intrinsic T2 distribution accentuates fine pore size variations and allows better discernment of micro-, meso-, and macropore systems of complex carbonate reservoirs.
Multi-frequency NMR data, acquired in multiple wells, were processed and analyzed in several ways. First, apparent T2 distributions were obtained separately for individual frequencies. Discrepancies between the results of different frequencies clearly indicated that in macro- and mesoporous carbonates the diffusion effect is significant even with TE=0.3ms. This leads a peak broadening observed in the apparent T2 spectrum from conventional NMR processing, where echo trains from different frequencies are averaged in time-domain prior to the inversion. With the IFMI processing, individual-frequency echo trains are first pre-processed using a 2D NMR inversion whose results are used to forward model a diffusion-free echo train without prior assumptions on reservoir fluid diffusivity D. A second inversion, applied on the diffusion-free echo train, yields the intrinsic T2 distribution. The intrinsic T2 distribution has a noticeably higher spectral resolution in carbonate formations where diffusion effect is significant. The intrinsic T2 logs are expected to be more consistent with other gradient-free NMR measurements such as core NMR or LWD NMR data sets.
Comprehensive Fracture Characterization in Tight Carbonate Reservoir Using LWD High-Resolution Image and Multi-Pole Sonic Measurement; A Case Study from Offshore North West Java, Indonesia
Authors: Irawan Debby , Wibowo Icuk Dwi , Martinauly Bertha , Fransiska Linda , Lilasari Leonora Ludwina , Permanasari Dian , Jhonny Jhonny 
Published: September 2021

Abstract
Tapping into an unconventional reservoir such as naturally fractured tight carbonate or basement has become more common in the industry. Open natural fractures, when present are the major contributor to production flow in such formation. Therefore, a comprehensive understanding of fracture properties including aperture, intensity, and permeability is required to identify the productive fractures and optimize production.
In this paper, we discuss the first application of the latest Logging-While Drilling (LWD) high-resolution laterolog resistivity image in combination with LWD multi-pole sonic to provide comprehensive fracture characterization in Pre-Talang Akar Formation tight carbonate reservoir, in the offshore North West Java Basin, Indonesia. The methodology involved identification of borehole breakouts, natural or drilling-induced fractures, faults and vugs from the high-resolution LWD image data, which were then interpreted further to provide the fracture attributes and the secondary porosity distributions from each of the identified features. The Stoneley measurement from LWD multi-pole sonic log enabled the analysis of the fracture system producibility using the sonic fracture technique. The characterization of fractures and faults (open/closed) from the integration of these two independent methods were complemented by the triple combo measurements, caliper, and drilling loss data, as well as sonic compressional and shear data.
This methodology has successfully managed to differentiate open fracture zones and closed fracture zones along with their computed fracture properties. The open fracture zones were characterized by a cluster of conductive fractures with large fracture aperture and fracture porosity value. These fractures were also associated with positive fracture indication from the sonic data, decrease in density logs, shallow - deep resistivity log separation and drilling loss occurrence. Whereas, closed fracture zones were characterized with minor fracture dip development. It also showed negative open fracture indication from sonic data, flat density log response and overlaying resistivity log response with no drilling loss occurrence.
The case study in this paper shows excellent LWD data quality and fracture characterization result, on par with wireline conveyed data that were commonly used to quantify fracture attributes. The results provide invaluable information for volumetric calculation, well completion and production planning in this area.
History Matching and Performance Prediction of a Polymer Flood Pilot in Heavy Oil Reservoir on Alaska North Slope
Authors: Wang Xindan , Keith Cody , Zhang Yin , Dandekar Abhijit , Ning Samson , Wang Dongmei , Edwards Reid , Barnes John , Girbacea Radu , Cercone David , Ciferno Jared 
Published: September 2021

Abstract
The first-ever polymer flood pilot to enhance heavy oil recovery on Alaska North Slope (ANS) is ongoing. After more than 2.5 years of polymer injection, significant benefit has been observed from the decrease in water cut from 65% to less than 15% in the project producers. The primary objective of this study is to develop a robust history-matched reservoir simulation model capable of predicting future polymer flood performance. In this work, the reservoir simulation model has been developed based on the geological model and available reservoir and fluid data. In particular, four high transmissibility strips were introduced to connect the injector-producer well pairs, simulating short-circuiting flow behavior that can be explained by viscous fingering and reproducing the water cut history. The strip transmissibilities were manually tuned to improve the history matching results during the waterflooding and polymer flooding periods, respectively. It has been found that higher strip transmissibilities match the sharp water cut increase very well in the waterflooding period. Then the strip transmissibilities need to be reduced with time to match the significant water cut reduction. The viscous fingering effect in the reservoir during waterflooding and the restoration of injection conformance during polymer flooding have been effectively represented. Based on the validated simulation model, numerical simulation tests have been conducted to investigate the oil recovery performance under different development strategies, with consideration for sensitivity to polymer parameter uncertainties. The oil recovery factor with polymer flooding can reach about 39% in 30 years, twice as much as forecasted with continued waterflooding. Besides, the updated reservoir model has been successfully employed to forecast polymer utilization, a valuable parameter to evaluate the pilot test’s economic efficiency. All the investigated development strategies indicate polymer utilization lower than 3.5 lbs/bbl in 30 years, which is economically attractive.
Enhanced Experimental Carbon Dioxide Sweep Using Surface Coated Silica Nanoparticles as a Foaming Agent
Authors: Alfakher Ahmad , DiCarlo David A. 
Published: September 2021

Abstract
Solvent flooding is a well-established method of enhanced oil recovery (EOR), with carbon dioxide (CO2) being the most-often used solvent. As CO2 is both less viscous and less dense than the fluids it displaces, the displacement suffers from poor sweep efficiency caused by an unfavorable mobility ratio and unfavorable gravity number. Creating in-situ CO2 foam improves the sweep efficiency of CO2 floods. Another application is the injection of CO2 foam into saline aquifers for carbon capture and storage (CCS).
The goal of the core flood experiments in this paper was to study the effectiveness of surface coated silica nanoparticles as an in-situ CO2 foaming agent. In each experiment, the pressure drop was measured across five separate sections in the core, as well as along the whole core. In addition, the saturation distribution in the core was calculated periodically using computed tomography (CT) scanning measurements. The experiments consisted of vertical core floods where liquid CO2 displaced brine from the top to the bottom of the core. A flood with surface coated silica nanoparticles suspended in the brine is performed in the same core and at the same conditions to a flood with no nanoparticles, and results from these floods are compared. In these experiments, breakthrough occurred 45% later with foamed CO2, and the final CO2 saturation was also 45% greater than with the unfoamed CO2.
The study shows how nanoparticles stabilize the CO2 front. The results provide quantitative information on, as well as a graphical representation of, the behavior of the CO2 foam front as it advances through the core. This data can be used to upscale the behavior observed and properties calculated from the core-scale to the reservoir-scale to improve field applications of CO2 flooding.