bluuebunny/crossref_metadata_2025_split huggingface dataset:
Use of Deconvolution for Pressure Transient Analysis in Layered Reservoirs – A New Method
Authors: Khalaf Mina S. , El-Banbi Ahmed H. , Sayyouh M. H. 
Published: January 2023

Summary
Many reservoirs exhibit multilayer behavior. Multilayer oil/gas reservoirs are usually classified as (1) systems with formation crossflow and (2) systems without formation crossflow (commingled systems). The focus in this work is the analysis of pressure transient data of commingled layers.
Pressure transient analysis for multilayer reservoirs to estimate individual layer properties is usually difficult and suffers from many limiting assumptions. The available interpretation methods are usually based on a subjectively presumed model (usually homogenous and isotropic layers, and radial infinite reservoirs) that has many unknown parameters (e.g., permeabilities and skin factors) to be estimated through a history matching process. The individual layer properties obtained from such analysis methods may not be reliable. The reliable way to evaluate individual layers’ characteristics is to isolate and test each layer separately, which is challenging due to high costs and occasional operational constraints.
In this work, we suggest a testing procedure and an analysis approach to analyze well test data of commingled reservoirs that allows reliable characterization of individual layers. The approach benefits from modern deconvolution techniques to eliminate the rate variation (rate transients) effects from the bottom-hole pressure signal acquired during the test. The methodology presented does not make assumptions about the individual layer reservoir models and recovers distinct pressure signals of the individual layers. The recovered pressure signals of each layer are also free of wellbore storage (WBS) effects. In addition, the individual layers’ pressure signals are stretched over the whole test duration (both drawdown and buildup periods).
Successful application of deconvolution requires complete sandface rate data of the individual layers in the commingled system. However, the continuous measurement of individual layers sandface rates is usually not available. A simple model is introduced in this work to make good estimations of the layer rate profile using few measurements of the production logging tool (PLT). The developed rate profiles are then used in deconvolution and individual layer's pressure signal can be recovered for further analysis.
The approach was verified against simulated cases with variety of layer models. The results obtained from the developed approach are in good agreement with the true solution. The findings of this study can be used to characterize commingled reservoir systems and determine the individual layers properties. It has applications in optimizing injection/production well performance of commingled systems.
Identifying and Characterizing Mass-Transport Complexes in the Longmaxi Shale in Sichuan Basin, China
Authors: Liang Xing , Shu Honglin , Zhang Jiehui , Luo Yufeng , Liu Bo , Zhang Xu , Zhao Chunduan , Li Shenzhuan , Sultan Gamal , Shasmal Sudipan 
Published: January 2023

Abstract
The Lower Silurian Longmaxi Shale Formation of Sichuan Basin is the largest shale gas reservoir in China. It was formed mainly in a deepwater shelf depositional environment with a relatively stable tectonic background. More and more cores and borehole images
data from the Longmaxi Shale revealed that the sedimentary features show considerable changes in mineralogy or texture in different regions. Mass-transport complexes (MTC) were identified for the first time in the Longmaxi Shale based on the integration of logs, borehole images, and seismic data. The MTC have led to a clearly abnormal formation thickening in both well and seismic data. Identifying and characterizing the MTC in the Longmaxi Shale is the objective of this case study.
The integration of the logs, borehole images, and seismic data brings more insights into different aspects of MTC. The repeat section that results from the MTC can be identified based on the well logs directly. Detailed analysis of the borehole images yields additional evidence such as lithofacies and textures in the MTC. The faults and fractures in the MTC can also reveal the controlling factors on the shale gas enrichment. The analogs between the concept model and seismic reflections have improved our understanding of when and how the MTC are likely to form in the Longmaxi Shale.
The MTC in the Longmaxi Shale are developed above the detachment surface between the calcite-cemented sandstone body and the high-clay-volume shale. It brings more than 20 m of repeat section inside the Longmaxi Formation. The boundary between the original and repeat sections is a low-angle thrust fault. The repeat sections can be divided into four zones based on their log responses. The gamma ray (GR) response and the borehole image features have validated the presence of the repeat section. The minerology differences between the original and repeat sections have highlighted the facies variations in the Longmaxi Shale. This is also the reason why the MTC could occur in this area. Based on the calibrations of well data, the geometry and architecture of the MTC are readily observed in 3D seismic data. The MTC in the Longmaxi Shale are formed in a slope background. It helps to get more understanding of the sedimentary variations in the Longmaxi Formation. The process of MTC forming may have a significant impact the reservoir quality of the Longmaxi Shale.
Study on Fracture Propagation Simulation With the Integration of Fully-Coupled Geomechanical and DFN Modeling
Authors: Fan Qinghu , Qu Gang , Xu Chuanyou , Zhang Chengbin , Wang Lixin , Bian Tengfei , Wu Xin , Zeng Congliang , Jia Fei , He Jiajun , Xu Hanbing , Huang Xingning 
Published: January 2023

Abstract
Junggar Basin is a typical superimposed oil and gas bearing basin in western China, where Mahu Depression is the largest oil-gas accumulation zone and exploration area. On April 23rd, 2013, the peak daily oil production of Mahu No.1 well reached 52 tons, achieving a significant breakthrough. On August 23rd of the same year, the high yield of Mahu No.18 well opened a new chapter of oil and gas exploration in the slope belt of the Mahu Depression. Since then, CNPC (China National Petroleum Corporation) has increased the exploration and development process of the Mahu Depression, establishing the exploration theory and technology system of the conglomerate reservoir in the depression area. Finally, the exploration and discovery of a supergiant conglomerate oil field (1 billion tons) were achieved. However, a series of development problems were exposed, which was due to the lack of in-depth research on reservoir geomechanics and distribution law for natural fractures: 1) The Hydraulic fracture propagation law is not clear; 2) In the process of fracturing, there exists an obvious phenomenon of non-uniform fluid inflow and expansion in various clusters of fractures; 3) Serious interference occurs between wells during the fracturing operation. Therefore, it is necessary to strengthen the study of geomechanics and distribution law for natural fractures in unconventional oil reservoirs, so as to provide technical support for the optimization of the horizontal well fracturing scheme, improvement of well pattern deployment parameters, and adjustment of oil reservoir development scheme, which further leads to cost reduction and development efficiency improvement while increasing single well production in unconventional oil reservoirs.
Application of Machine Learning in a Giant Mature Reservoir to Speed-Up Infill Prospects Screening, Optimize Field Development and Improve the Ultimate Recovery Factor
Authors: Fabbri Clement , Reddicharla Nagaraju , Shi Wen , Al Shalabi Alaa , Al Hashmi Sara , Al Jaberi Sulaiman 
Published: January 2023

Abstract
In giant reservoirs, production sustainability strongly depends on the identification of opportunities for infill drilling. This paper presents the use of Machine Learning to speed-up and improve the efficiency of the evaluation of future infill wells, in an effort to optimize field development of a Giant Mature reservoir Onshore Abu Dhabi.
In the mature giant carbonate reservoir studied, more than 420 wells are already drilled with consistent spacing but with varying orientations. This paper illustrates some examples of settings that are difficult to assess without geometric calculations, leading to time-consuming opportunity identification and classification.
The minimum set of input for the program includes existing wells trajectories, faults polygons, contact, and production data. Users can define the minimum drainage area for each well, maturity criteria and drain length. For each subsurface target identified, a polygon and simulation input are generated. The Python program is developed and run on an in-house platform and solve the future wells positioning in three main steps: (1) Geometric screening and identification of locations with required spacing, (2) Analysis of nearby well performance, (3) automatic generation of simulation input for evaluation of the subsurface target.
A Simulation Model With Unstructured Grid Provides Better Predictions of Water Movement in Heavily Fractured Reservoir – A Case Study at Onshore Abu Dhabi
Authors: Shi Wen , Marzooqi Maitha Jawhar Al , Ansi Rasha Nabeel Al , Zhou Shuisheng , Li Junchao , Gong Bin , Fang Junling , Li Chen , Yang Tao 
Published: January 2023

Abstract
A multi-billion-barrel oil reservoir at onshore Abu Dhabi has been developed under depletion/aquifer water drive for over 30 years. Recently, significant number of producers have encountered water breakthroughs, some of which are highly suspected to be through the connected fracture network naturally occurred in the reservoir. This premature water breakthrough behavior has hindered the company's mission of increasing and stabilizing the oil production from this reservoir. Predicting future water production, optimizing infill drilling locations and implementing water injection remain as main challenges that the operator has faced.
The study described in this paper deployed multiple levels of fracture characterizations in the reservoir simulation model by using unstructured grid to explicitly delineate major/large fractures. The multiple rounds of well-by-well history match has been conducted with focus on water production behavior and pressure. Special attention has been put on the wells showed premature water breakthrough and on the wells identified as "dominated by fractures". The history match process involving many multi-disciplinary work sessions utilized well test data, image logs, seismic data and mud losses to ensure the most meaningful adjustments on fractures descriptions to be implemented.
In comparison with the ordinary dual-porosity dual-permeability (DPDP) reservoir simulation model that has been used during the past few years by the operator, this novel approach / new unstructured grid model provides much better fracture descriptions, higher quality history match and more reliable predictions. Its faster run speed may attribute to its adaptive mesh refinement treatment. The history match has shown significant improvements especially at wells that are dominated by flow through fractures. The current forecast exercise focuses on screening of infill locations and ranking of pre-mature water breakthrough risks at locations. Effect of peripheral water injection are also part of the prediction. The ultimate success criterion is reducing/eliminating pre-mature water breakthroughs at infill well locations optimized by this model.
Effective Modeling of Stimulation and Production Decline From Tight Naturally Fractured Carbonate Reservoirs
Authors: Peshcherenko Aleksandra , Anisimov Mikhail , Chuprakov Dimitry 
Published: January 2023

Abstract
Tight naturally fractured carbonate reservoirs often show steep rate and pressure declines leading to reduction in apparent well productivity. These declines are influenced by several complex phenomena. Some of these are geometry and density of natural fractures (NFs), matrix properties, and damage that occurs during the drilling and completion operations. An additional factor which is sometimes overlooked is the change in NF properties (such as decrease in NF permeability) with time that occurs because of production drawdown. Modeling this phenomenon forms the focus of this paper.
Injection or production of fluid in naturally fractured reservoirs (NFRs) typically causes slippage, opening, and fracture compliance effects that depend on elevation or decrease of fluid pressure in the rock. In this work, we solve equations of fluid transport in a rock with a high density of NFs using constitutive equations for hydro-mechanical fracture response to pressure changes and chemical reactions with the injected acids. Followed by the acid treatment and shut-in periods, we model the production phase. For the production modeling, we specified a flowing bottomhole pressure (FBHP) and studied the production rate decline as a function of time.
The production decline is a result of NF permeability decrease, which is due to the increase of effective stresses applied to NFs. We show sensitivity of these production signatures to spatial density of NFs and viscosity of treatment fluids. We also demonstrated changes of anisotropic formation permeability tensors both after the shut-in and during production for two types of stimulation: mechanical and chemical formation damage.
Common reservoir engineering workflows sometimes ignore well-known time-dependent rock mechanics behavior of NFs. The work presented in this paper will help quantify NF conductivity loss with producing time which is an important parameter in numerical reservoir simulations. Decline rates in tight NFRs are steep and impact EURs and project economics. Therefore, understanding the mechanisms that influence these declines through fit-for-purpose modeling and simulation is a crucial step for optimizing their development.
Internally Catalyzed Aqueous-Based Emulsion of Curable Epoxy Resin Sand Consolidation Treatment Extends Economical Production in Austria's Mature Oil and Gas Fields.
Authors: Trujillo Erika Johana Tovar , Santin Yoann , Ukoha Obinnaya , Caldarelli Riccardo , Maier Robert , Kiss Akos , Moertl Monica , Zabel David 
Published: January 2023

Abstract
Sand production is one of the major challenges for mature fields in Austria. With increasing water production, the severity of the sand migration augments, leading to the shut-in of the wells. Eliminating or substantially reducing sand production at the sand face is the most viable option to continue hydrocarbon production. The project's target was to research and apply a technically sound solution readily available in Europe, with reduced HSSE risks and little economic impact.
To control intervention costs, it was decided to favor sand control solutions for rig-less interventions. Collaboratively, the teams evaluated formation rock consolidation with the help of an internally catalyzed aqueous-based emulsion of curable epoxy resin (ICABECER). Laboratory testing demonstrated the system's suitability for the target wells and confirmed the viability of the planned operations scheduled to deploy the treatment via coiled tubing (CT), as well as limiting concerns about permeability reduction. Finally, field operations of the application, clean-up, and production face were monitored and evaluated.
The major concern when using resins to agglomerate sand grains in a reservoir rock is that the pore space is reduced, jeopardizing the rock permeability. Laboratory testing confirmed that the permeability of the rock can be retained. Due to the simplicity of the intervention, the treatment could be deployed with standard equipment keeping it within the budgetary constraints of very mature fields.
To mitigate possible risks, wells having challenging production backgrounds and scheduled for plug and abandon were selected. In these wells, previous conventional sand control measures failed, such as gravel pack installations or attempting to produce sand and separate it on surface. Post-job results demonstrated that the in-situ consolidation generated a reduction of sand content to a level allowing production of the wells. During the clean-up period of the gas well, sufficient sand was produced to erode the choke. After the well start-up period, sand production was eliminated, and the well was returned to the target rate. Monitoring of solid contents in the flow and the evaluation of coupons confirmed the suitability of the technique to establish flow with acceptable risks contributing to economic success.
The cost-effective ICABECER chemical treatment, along with the methodology, opens new opportunities for the asset to prolong well life and increase the overall recovery factor from the reservoir. Technical simplicity and the reduced environmental impact of the chemicals are key for resource-saving and sustainable operations in mature fields.
A Reduced-Physics Framework for Forecasting in Unconventional Reservoirs
Authors: Guo Zhenyu , Li Ying , Sankaran Sathish 
Published: January 2023

Abstract
Forecasting in unconventional reservoirs is a challenging task due to its complex physics. While decline curve analysis (DCA) is the ubiquitous workhorse for forecasting production rates, it often is not adequate in several scenarios without consideration of physics. Alternately, full-physics reservoir simulation models are equipped with comprehensive physics; however, they are often tedious, time-consuming, and data-hungry due to their underlying requirements on geological modeling, fracture modeling and model calibration. The goal of this work is to apply a reduced-physics framework (RGNet) for modeling, conditioning, and forecasting unconventional reservoirs in an efficient manner, while preserving the fundamental flowing physics to ensure prediction accuracy.
Based on the concept of diffusivity of time of flight, RGNet models the drainage volume of a target well using a set of 1D grid blocks in lieu of a detailed 3D grid system, which significantly reduces the complexity of the system and enables faster model runtime. Since RGNet constructs a reservoir model with a completely different frame of reference by simply following pressure evolution patterns originating from the well, it removes the burden of geological/fracture modeling. The parameters defined in the 1D grids are common reservoir properties that are physically interpretable such as transmissibilities and pore volumes which are calibrated by history matching routinely measured data (rate, pressure). In addition to common reservoir-flow physics, pressure-dependent properties are considered inside the framework as the physics specific to unconventional reservoirs.
The proposed framework is applied for multiple field examples with multi-phase production including gas and oil reservoirs. The field examples demonstrate that we can obtain reasonable history matches under single-well and multi-well scenarios. Reservoir properties are reasonably characterized, including relative permeabilities, well indices, pore-volumes, transmissibilities and well interference. Furthermore, the tests on oil reservoirs show good prediction of gas-oil ratio changes, which is typically difficult to achieve using analytical or empirical approaches. By using an ensemble-based history-matching algorithm, RGNet also provides multiple history-matches and forecasts for uncertainty analysis. As RGNet uses a parsimonious method for modeling the reservoir, the runtime of one forward model is only a few seconds for all the examples presented, which is much faster than a full-physics model.
RGNet provides an efficient way to model, history match, characterize and forecast unconventional reservoirs. It provides a generic framework so any relevant physics can be incorporated. As common reservoir properties are used to parameterize reservoirs, the results are easily interpretable. The superior efficiency of RGNet makes it suitable as a fit-for-purpose tool for well performance analysis and continuous production optimization in unconventionals.
What is the Acceptable Cluster Interference Degree in Multistage Hydraulically Fractured Wells?
Authors: Ibrahim Ahmed Farid 
Published: January 2023

Abstract
The cluster spacing was set up to 700 ft in diffrent shale formations including Bakken and Barnet shales. Howerver, tight cluster spacing was applied in apart in Eagle Ford and DJ Basin for cluster spacing up to 15 ft. The tight fracture spacing was applied to ais to increase the initial production rate. However, a higher initial production rate is at the expense of higher operation and completion costs in addition to operational complexity. This study presents an combined workflow to calculate the percent of interference and its effect on the well performance in addition estimate the acceptable interference degree that provides the highest well profitability.
Analytical rate transient analysis (RTA) and reservoir numerical simulation were combined to estimate the ratio of the effective fracture surface area (ACe) for hydrocarbon production to the actual stimulated fracture area (ACa) from the numerical simulation. The degree of interference was calculated by (1- ACe/ACa). The economic study was added to the integrated workflow to estimate the degree of interference and the optimum spacing based on the profitability of the well.
This study presents an integrated workflow to quantify the degree of cluster interference as a function of spacing. The workflow was integrated with an economic model to estimate the acceptable interference percent to have a higher NPV. The higher the stage number and tighter cluster spacing, the higher the cluster interference will be. The acceptable interference percent is a function of formation properties and economic parameters. The acceptable interference percent was found to be 16% in the case of 0.0001md, 2.5$/Mscf. Increasing the formation permeability increases the acceptable interference percent to accelerate production and increase the recovery. As the gas price increases, tighter spacing is recommended, where, at 8$/Mscf, the NPV was continuously increasing up to the lowest spacing in this study of 20 ft.
This study provides an integrated workflow to quantify the interference percent and the acceptable percent as a function of cluster spacing, formation properties, and economic analysis in order of increasing the well profitability.
Effect of Variable Brine Salinities on CO2 Trapping: Implications for CO2 Storage in Saline Acquires
Authors: Zhang Haiyang , Al Kobaisi Mohammed , Zhang Yihuai , Arif Muhammad 
Published: January 2023

Abstract
Injecting CO2 into the saline aquifer is considered to be an effective strategy to mitigate CO2 emissions. Saline aquifers are known to have a wide range of salinities and several evidences showed that different brine salinities give rise to different CO2-brine-rock wetting behaviors as well as different CO2 solubility potential. This will ultimately influence the CO2 plume migration behavior and the overall performance of a CO2 sequestration project. However, associated field-scale CO2 capacity predictions in different saline aquifers received little attention. This study conducts field-scale numerical simulations to analyze the effect of aquifer salinity on the CO2 storage potential. Different CO2-brine flow behaviors undervariablebrine salinities were considered. The results showed that an increase in the plume migration distance was observed in a higher salinity aquifer.While an increase in the brine salinity would result in an increase in residual trapping but a decreased solubility trapping capacities.Also, higher salinity formation observed more mobile CO2 and thus exhibit a worse sealing efﬁciency. We point out that residual trapping capacity evaluation should consider both residual CO2 saturation and the CO2 occupied volume, which both are strong functions of brine salinity.