bluuebunny/crossref_metadata_2025_split huggingface dataset:
Reservoir Quality Vertical Heterogeneity Characterization in Shale Oil Reservoir, a Case Study from Junggar Basin
Authors: Gan Ren Zhong , Fu Lian Ming , Fang Tao , Wang Wei , Cai Liang , Wu Jin Long , Zhao Xian Ran , Li Liu Zhong 
Published: February 2024

Abstract
Compared with the marine shale oil resource conditions in the United States, the lacustrine shale oil resource conditions in China are different and the lithology is complex. At present, PetroChina has successfully conducted shale oil horizontal well exploration in such strata as Fengcheng Formation in MaBei, Xinjiang, Kong2 member of Cangdong sag in Bohai Bay, and Qingshankou in Songliao basin has made some progress. However, the understanding and evaluation of "sweet spot" are not perfect, which results in some misleading information for current shale oil exploration, and it brings great challenges to test layer selection and horizontal well landing window selection. Vertical heterogeneity places additional obstacles for reservoir characterization. This paper introduces an integrated methodology for reservoir quality vertical heterogeneous characteristic identification and evaluation in shale oil reservoir by integrating advanced spectroscopy, 2D nuclear magnetic resonance (NMR), and borehole electric image data. Vertical heterogeneity for reservoir quality characteristics includes mineralogy and lithology, rock texture, total organic carbon (TOC), porosity and pore structure, and water saturation. Mineralogy and TOC difference was recognized by the advanced spectroscopy logging data. Rock texture was defined with an innovative edge detection method to identify the lamination status throughout the reservoir. T1-T2 based 2D NMR will solve for porosity, pore size distribution, and fluid identification. Case studies are presented from a shale oil reservoir in the Junggar Basin of Western China. Vertical variety inside the Fengcheng Formation is well defined based on several specs in this case study, including mineralogy and lithology, kerogen distribution, porosity and pore size distribution, and oil-water distribution; the reservoir producibility index was further calculated based on integrated analysis. From the vertical heterogeneity recognized from the above methodology, the sweet spot and horizontal well landing window was successfully recognized. In this paper, we discuss a novel combination of advanced logging methods in unconventional reservoirs, which can help the operators to analyze the reservoir quality vertical heterogeneous character of these reservoirs. The fine reservoir evaluation process helps to define the best oil zones, which will help ascertain the potential of the reservoir and boost the promising oil production. The integrated workflow illustrated in our case studies can be applied and extended to the exploration of other unconventional reservoirs in China.
Mechanical Properties of Cenozoic Organic-Rich Shale from North Sumatra and South Sumatra Basins, Indonesia
Authors: Lanin E. S. , Sone H. , Sapiie B. , Musu J. T. , Widarsono B. , Hatta M. , Nugraha A. , Gunawan B. K. , Nugroho D. A. 
Published: February 2024

Abstract
Indonesia is actively studying its shale resources’ potential to be developed. In contrast to other countries that have succeeded in developing their shale resources, Indonesian shale potentials are generally located at an active tectonic margin and are of younger ages (Cenozoic Era). This condition raises questions about the sustainability of its mechanical properties and development technique. Following our previous research, this paper presents the results of rock mechanical tests on shale from North Sumatra and South Sumatra Basins. The shale samples were prepared and tested by a rigorous multi-stage triaxial procedure. Eight (8) plugs representing the Baong and Belumai Formations of the North Sumatra Basin and eight (8) plugs representing the Talangakar and Gumai Formations of the South Sumatra Basin were prepared in vertical (V), horizontal (H), and 45° inclined (I) orientation relative to bedding. The test stages can be broadly categorized as the hydrostatic stage, triaxial stage, failure stage, and sliding-re-sliding stage. All the tests were conducted at a maximum confining pressure of 30 MPa to compare the results with results of our previous study and results from U.S. Shales. The tested shale plugs possess higher porosity than U.S. Shales for a given clay + organic matter (OM) content. Regarding rock strength, the analyzed plugs show a correlation with clay + OM content and inter-granular porosity. For the elastic properties, Young's modulus shows a decrease with clay+ OM contents, unlike the Poisson Ratio, which does not offer a clear trend. Meanwhile, creep compliance clearly shows the inverse trend of Young's modulus. The anisotropy of elastic properties is demonstrated by sample orientation, where the horizontal sample is the stiffest, the vertical sample is the softest, and the inclined sample is in between. Generally, the mechanical properties of the plug samples from Baong, Belumai, Talangakar, and Gumai Formations coming from two tertiary basins in western Indonesia show a relationship with clay+ OM content, in line with U.S. Shale data. However, regarding compressive strength and Young's modulus, the relatively younger western Indonesian samples show lower values than most. The novelty of this study is to report and analyze, for the first time, the anisotropy elastic properties of Indonesian shale samples by incorporating inclined-oriented samples in addition to the vertically and horizontally oriented samples. The results of this study also supported the mechanical maturity hypothesis from our previous research. Nevertheless, it needs to be tested further by analyzing samples from the eastern Indonesian basin, which generally has older source rocks (Mesozoic Era).
CO2 Soluble Surfactants Assisted Carbon Storage Under Achievable Pressure Gradients: Effect of Surfactant Partitioning Behavior During Continuous CO2 Injection
Authors: Ding Lei , AlSofi AbdulKareem M. , AlMajid Muhammad M. , Patil Pramod 
Published: February 2024

Abstract
Injecting CO2 into the saline aquifers normally suffers from low sweep efficiency due to the smaller density and viscosity of CO2 compared to brine. The potential of CO2 soluble surfactants assisted carbon storage in carbonate formations was first evaluated by core flooding tests (at 65°C, 150 bar & 90,000 TDS) in Indiana Limestone at different gas fractions, where the surfactants were injected with the CO2 phase (CCI+S). The pressure gradients and CO2 saturation were continuously monitored during the coreflooding tests. It was found that foam was generated during CCI+S when 0.07 wt.% of surfactant was injected with CO2. Moreover, the CO2 saturation at steady states can be significantly enhanced in the presence of foam from experimental observations. The CO2 saturation reached 60% (compared to 32% without surfactant) after 1.5 PV of CCI+S. The maximum pressure gradient was approximately 1.5 psi/ft in 162 mD Indiana Limestone at a Darcy velocity of 1.0 ft./d, which is technically feasible for field applications. Furthermore, an improved foam model incorporating the surfactant partitioning behavior was developed to obtain the foam modeling parameters by history matching the steady-state foam behavior. The effect of surfactant partition on CO2 transport behavior was studied by a 1D synthetic model at a lab scale and 2D synthetic homogeneous/heterogeneous models at the field scale, using modeling parameters and surfactant concentrations that are realistic for field tests. The sensitivity analyses imply that the CO2 storage efficiency largely depends on surfactant partitioning behavior (Ksgw), dispersivity, and formation heterogeneity, etc. The simulation results also indicate that there may always exist an optimal Ksgw for CCI+S, which satisfies both good CO2 sweep efficiency and acceptable injectivity. The advantages of injecting the surfactant with CO2 are more evident in heterogeneous saline aquifers, indicating an enormous potential of CCI+S for carbon storage. The novel injection strategy provides a promising solution for carbon sequestration in saline aquifers.
Rheological and PVT Behavior of Synthetic Based Drilling Fluids Under Temperature-Pressure Conditions of the Riser in Deepwater Drilling
Authors: Yanik S. , Gucuyener I. H. , Sinayuc C. , Akel O. F. 
Published: February 2024

Abstract
Invert emulsion drilling fluids (IEDFs) are water-in-oil emulsions in which the water phase is usually calcium chloride brine as the internal phase and the non-aqueous fluid forms the external phase. They are widely used to drill troublesome shale formations thanks to their main advantages of excellent shale inhibition mechanisms, superior lubricity, and high-temperature stability. The challenges of deepwater drilling operations necessitate the use of invert emulsion systems, and due to environmental regulations, synthetic fluids as a base oil are preferred. Hydraulic optimization in deepwater drilling requires the use of temperature- and pressure-dependent rheological properties and density due to the wide range of temperatures and pressures anticipated in these wells. Temperature- and pressure-dependent rheological properties and density are necessary for managing typical drilling problems such as barite sag, excessive equivalent circulating density (ECD), lost circulation, well control and poor hole cleaning. This study experimentally investigated the rheological and PVT behavior of synthetic-based drilling fluids at low temperatures or high pressures that may occur in the riser during drilling and well control.
Synthetic-based drilling fluids were formulated at three different synthetic-water ratios (70/30, 80/20, and 90/10) and four different densities (10, 12, 14, and 16 ppg). EDC99 DW and 25% calcium chloride were used as the external and internal phases, respectively. Rheological and PVT measurements were performed over a temperature range of 40 to 70 °F and a pressure range of 14.7 to 12,500 psi using the Grace M7500 Ultra HPHT Rheometer and PVT module. Plastic viscosity (PV), yield point (YP), 10 s/10 min gel strength and density of IEDF samples were evaluated as a function of temperature and pressure. Additionally, rheological properties and static/dynamic density profiles of the fluid were obtained in a sample deep water well using a temperature-pressure dependent hydraulic simulator, and the results were compared with the traditional approach.
Practical Guide to Successful Application of Using 6.75 Inch Slim Fluid Sampling While Drilling Tool Across the Large 12.25 Inch Wellbore
Authors: Zhang W. , Rao Z. , Deng C. , Liu C. , Zuo K. , Zhou J. , Wang L. , Benyoucef B. 
Published: February 2024

Abstract
The objective of this paper is presenting and highlighting the application of the successful 6.75 inch reservoir Fluid Sampling While Drilling (FSWD) technology in a very challenging well condition: 12.25 inch borehole, S-shaped well trajectory, and unconsolidated sand reservoir. The available FSWD tools are 6.75 inch outer diameter developed for 8.5 inch wellbore. Through reasonable tool design and operation process, the 6.75 inch FSWD technology was performed successfully at this 12.25 inch borehole challenging condition and achieved perfect results.
Development Well A was drilled in 12.25 inch with an S-shaped well trajectory to pass through multiple target zones: the inclination increased to 68° after vertical section, and decreased to 43° in Z formation. In order to guide the subsequent perforation operations, which is avoiding perforating at gas zone, the operator planned to conduct Fluid Sampling While Drilling operations in Well A to determine the accurate depth of gas-oil contact of Z formation, and to obtain pure gas, oil and water samples for laboratory analysis. To realize the successful sealing by using the 6.75 inch slim tool in the 12.25 inch wellbore, the "Low-side sealing" method was used which is adjusting the probe face to the low side of wellbore during the pressure testing and sampling all the time, using the tool's own weight to provide the required probe sealing force. Keep the mud circulating during the measurement to minimize deployment risk and tools stuck in S-sharped deviated wellbore.
A total of 18 pressure tests were performed, operation record shows that by adjusted the probe face at low side within 180°±15°, 100% sealing success rate was achieved. With the accurate pressure gradient result, the gas-oil contact of Z formation was confirmed successfully. Gas, oil and water samples were filled into 22 tanks from 6 sampling stations without any sand-plug situation. The maximum cleanup time was 4 hours prior to collecting 6 liters of reservoir water samples for area studies purpose and no stuck tools events recorded in all sampling stations.
By using "Low-side sealing" method, 6.75 inch slim Fluid Sampling While Drilling technology have the capability of acquiring representative fluid samples efficiently in a 12.25 inch deviated wellbore unconsolidated sand formation within an acceptable operation time and without sand plugging or tool stuck. This operation also created many China offshore operation records such as the highest stations of sampling and the longest pumping time (till Feb-2023).
Acrylic Acid-Modified Cellulose Nanocomposite: A Promising Green Solution for Shale Inhibition in Water-Based Drilling Fluids
Authors: Murtaza Mobeen , Rana Azeem , Kamal Muhammad Shahzad , Nadeem Sohail , Mahmoud Mohamed 
Published: February 2024

Abstract
Drilling operations in shale formations often encounter challenges due to wellbore instability caused by shale expansion. Addressing this issue is crucial to minimize non-productive time and control associated costs. In this study, we synthesized acrylic acid-functionalized cellulose diacrylate carbon nanocomposite and investigated its potential as a shale swelling inhibitor and fluid loss controller in water-based drilling fluids. To evaluate the inhibitory effects, linear swelling tests were conducted using varying concentrations (0.2, 0.5, and 1.0) wt%. Furthermore, rheology and fluid loss tests were performed to assess the performance of the drilling fluids.
The experimental results demonstrated a significant reduction in linear swelling of bentonite clay with the addition of nanocomposite. The extent of reduction correlated with the concentration of nanocomposite, with reductions of 37.06%, 46.63%, and 56.8% observed at concentrations of 0.2%, 0.5%, and 1.0wt% respectively, compared to deionized water. The nanocomposite improved the rheological parameters as plastic viscosity, yield point and gel strength parameters enhanced. The carrying capacity of the drilling fluids improved with the addition of nanocomposite. Moreover, the inclusion of nanocomposite resulted in a notable decrease in fluid loss. The fluid loss of nanocomposite mixed drilling fluid was reduced by 26% compared to the base fluid. This reduction was attributed to the formation of a compact film that effectively blocked nanopores, impeding water invasion.
The findings of this study highlight the strong candidacy of nanocomposite as an environmentally friendly shale inhibitor alternative for water-based drilling fluids.
From Lab to a Successful Field Operation: In-Situ Polymer Gel with Adsorption System for Water Shutoff Application
Authors: Almohsin A. , Sharma H. , Alabdrabalnabi M. I. , Kharrat W. 
Published: February 2024

Abstract
Robust and cost-effective water shutoff technologies are required to improve oil recovery and avoid challenges such as undesired water production. Herein, we present a new chemical water shutoff technology: A composite polymer gel system for carbonate substrate formation, from research work to successful field implementation.
The composite gel with controlled gelation time was developed to isolate water production zones over various parameters, including temperature, pressure, injectivity duration, and flow rate. The rheological property of matured gels was investigated, such as the storage modulus (G'). In addition, a robust process was implemented based on rigorous job design and preparation, precise execution with real-time downhole monitoring, and thorough post-job analysis. Indeed, production logging and a noise tool were run to confirm the water entry and ensure good cement isolation behind the casing across the target zone.
Laboratory results revealed that the gelation time can be controlled by varying the amount of fluid component, allowing a predictable pumping time at the given temperature between minutes to more than 10 hours. The gel system showed a significant pressure increase after the treatment, with good durability and effective water shut-off during the extended core flooding experiment. Thus, it is in alignment with gel strength testing. Hence, during the job mix adequate formulations based on the real-time downhole temperature, recorded while simulating the formation cooldown during treatment squeeze between retrievable plug and inflatable packer. The bottom hole circulating temperature and pressure were then measured in real time to adjust the water shutoff fluid formulations and to avoid exceeding the differential pressure limitation of the inflatable packer. After squeezing and waiting on the gelation of the water shutoff fluid in three stages, a successful pressure test demonstrated that the high water cut zone is reduced. Analysis of the pre and post job through rate test using downhole production logging tool (PLT); confirmed the success of treatment with a significant reduction in water production for more than 60%.
The new trend of using in-situ composite gel incorporated with adsorption system is a breakthrough water shutoff technology. Utilizing laboratory coupled with field data collected before, during, and after gel injection along with proper diagnostic are the key elements to increase the success rate.
Environmentally Friendly Shale Inhibitor Water-Based Drilling Fluids
Authors: Alqahtani H. S. , Alarfaj M. K. , Alotaibi M. A. 
Published: February 2024

Abstract
Environmentally friendly Mobil crystalline materials (MCM-41) from the family of Mesoporous Silica Nanoparticles (MSNs) has been used for the first time as shale inhibitors in water-Based Drilling Fluids with full drilling fluid compositions. This shale inhibitor used in this study to eliminate the use of toxic high potassium chloride (KCl) concentration in shale drilling operations and reduce the waste management associated cost with drilling fluid treatment and disposal.
The hot rolling dispersion test of MCM41 shale inhibitor with Silurian shale samples revealed to be an effective candidate with significant interaction reduction between the drilling fluids and the shale particles. This new shale inhibitor maintains the integrity of the cuttings and minimize the interaction of fluids with shale sections during the rolling test. XRD, TEM and TGA have measured and discussed in previous publication.
Although the application of nanoparticles to improve the performance of conventional water-based drilling fluid was studied by researchers, it is the novelty of this research to eliminate use of KCl and to develop the new generation of shale water-based drilling fluid with economical consideration and lower environmental impact.
Impact of Horizontal Well Open Hole on Sweep Efficiency in a Polymer Flood
Authors: Al Ghailani Taher , Al Sawafi Marwan , Al Mukhaini Salim 
Published: February 2024

Abstract
Marmul Polymer Phase 3 project is considered as one of the largest projects from CAPEX and Production perspective for PDO. The project calls for the re-construction of the existing urban plan and expansion of on-plot facilities to enable the drilling of an additional 400+ infill wells within Marmul field. The new vertical infill patterns will interfere significantly with the current well stock of the field. One of the activities called for by the field development plan is to abandon the horizontal wells that would cause interference and disturb the sweep efficiency of the new injectors.
Historically, around 120+ horizontal producers and injectors wells were drilled in Marmul field and most of them are still active. The existence of the horizontal wells in a field where vertical wells are planned for phase 3 could pose some risks like interference, poor sweep, or collision risk during drilling. Consequently, two scenarios have been considered to deal with the existing horizontals as the infill project is executed: 1) Keep the horizontal producers active until they deteriorate in performance 2) Abandon the horizontal producers when the vertical infill wells are drilled. A screening of all the existing horizontal wells was carried with consideration of production performance, it was decided to abandon wells with a certain production cut-off and the ones that would cause difficulty in drilling the new wells.
The field development plan did not specify if the horizontal section was needed to be abandoned, hence it was necessary to take technical driven decision to bring the resources to carry such operations. In order to assess the impact of not abandoning the horizontal section on the sweep efficiency of the vertical 9-spot patterns, a box model with average properties was run and a sensitivity analysis on the impact of distance between the horizontal well and the injector on the ultimate recovery. From the simulation and economic analysis, it was concluded that there is a risk of reducing both EUR and NPV by -20%, and hence we would need to abandon the whole horizontal section in order not to jeopardize the promised recovery for wells that lie within the pattern.
Usually turning off a well in a simulation model would consider the well nonexistent, hence it would have no impact on the nearby wells. what was done in the analysis is include keywords in order to shut-in the well from surface but keep the horizontal section open to the flow equations within the grid. This allowed us to quantify the impact of the well and take a decision on how to abandon these wells.