bluuebunny/crossref_metadata_2025 huggingface dataset:
Analysing Down Hole Scale Deposition in Offshore ESP Wells: A Case Study on Formulating an Effective Mitigation and Inhibition Strategy
Authors: Uniyal Rishabh , Jaruhar Suman Kumar , Sarkar Manoj Kumar , Devshali Sagun , Parida Dibyajyoti , Bhoye Sushil , Kanwar Manav
Published: September 2022

Analysis of recovered scale samples deposited within Electrical Submersible Pumps in offshore wells was carried out. The primary objective includes the identification of root cause of deposition and suggesting remedial measures for removal and prevention.

Many wells in an offshore field in ONGC are facing an acute problem of decrease in pump efficiency and ultimate failure of Electrical Submersible Pumps due to deposition of inorganic scale. The methodology for carrying out the study consists of a detailed Compositional Analysis of a sample of scale retrieved from inside the ESP of one of the affected wells. Additionally, X-Ray Diffraction analysis of the debris and compositional analysis of produced water sample from the same well were also carried out. The results of the experiments were corroborated by software simulation in Scale Prediction Software. Experiments were also carried out to identify a suitable inhibitor which could operate at high bottom hole temperatures experienced in the affected wells for preventing any future deposition.

Based on the compositional analysis of the scale and simulation runs using the produced water analysis, it was established that deposition of hard, adherent sulphate scale was the primary reason behind the choking and subsequent failure of the ESPs. In-situ conditions leading to deposition of the scale including variations in the operating environments and the effect of pump sizing have also been discussed.

The paper analyses the problem of inorganic scale deposition in offshore ESPs of ONGC utilising actual scale samples retrieved while dismantling the pump. An attempt has been made to provide an insight into the driving mechanism behind deposition inside the pump and various factors leading to it. The paper also details extensive lab experiments carried out to identify suitable inhibitors for high temperature application.
A Systematic Approach to Simulation Hydraulic Fracture Propagation by Implementing Natural Fracture Modeling in Unconventional Reservoir
Authors: Qu Jianhua , Zhang Boning , Deng Qi , Luo Bo , Xue Heng , Huang Jing , Huang Xingning , Guo Songyi
Published: September 2022

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.
Systematic Evaluation of Stoneley Mobility and Its Petrophysical Application Conditions
Authors: Saif Mohamed , Ma Shouxiang , Naqeeb Ibrahim , Ghosh Krishnendu , Abdallah Wael
Published: September 2022

In this study, a comprehensive workflow of estimating formation mobility using Acoustic Stoneley wave was evaluated, with diverse subsurface conditions and drilling environments including hole size, mud type, formation lithology, and formation fluids. The outcome of this exercise aimed to compare inverted Stoneley mobility and that from formation testing. The parameters tested with high significance on Stoneley mobility are mud acoustic slowness, mud acoustic attenuation, and the mud cake membrane stiffness. Analysis applied on these parameters showed a variation of uncertainty as well as sensitivity to mobility, with mud cake membrane stiffness being the most uncertain, and mud acoustic slowness and attenuation being the inputs with high sensitivity.

The findings of this study suggest that Stoneley mobility inversion can be used to quantitively estimate a continuous mobility log in clastic formations, a great value with many applications such as optimizing formation testing depths and, on a multiwell scale, in permeability characterization. It is therefore recommended that the Stoneley mobility be integrated in integrated studies for clastic reservoirs, serving as an intermediate measurement between the high resolution and accurate core permeability and formation testing mobility, and that derived from Drill Stem Tests; all are discrete measurements. It is also observed that, when comparing with formation testing results, applying the same Stoneley mobility inversion in heterogeneous carbonate formations seems challenging, an area for further study.
A Novel Correction Method for Pressure Transient Analysis Results of Horizontal Wells in Stratified Carbonate Reservoir with High Permeability Zone
Authors: Ma Ruicheng , Zhao Zeqi , Li Yong , Zou Chunmei , Hu Dandan , Chen Yajing , Zhang Leifu
Published: September 2022

High permeability zone (HPZ) formed by sedimentation and diagenesis has been founded in numerous oil fields in Middle East. Meanwhile, horizontal well have been applied universally in these oil fields. To obtain wellbore status and reservoir properties, pressure transient analysis (PTA) is a convenient and economic surveillance method. However, when it comes to stratified reservoir, heterogeneity between layers should be noticed. Log-log plot of actual data will be far form ideal analytical solution with homogeneous hypothesis. Therefore, the interpreted results would not be representative for wellbore and reservoir condition. In this research, we proposed a novel correction mathematical model and correction workflow for PTA results of horizontal wells in stratified carbonate reservoir with HPZ. This research innovatively imports production performance analysis and other monitoring methods to PTA in the view of flow field. This new approach holds favorable potential to provide accurate wellbore status and reservoir parameters for making the most use of surveillance budget.
Significance and Implications of Diagenetic Nodular Anhydrite on Sandstone Reservoirs Quality
Authors: Khalifa Aqeel , Tarabbia Paul , Alrowaie Mohammad A. , Soua Mohamed
Published: September 2022

Diagenetic nodular anhydrite observed in fluvio-aeolian-lacustrine and glacial sandstones has significant implications to reservoir quality. This type of nodular cement is spatially and volumetrically variable within these reservoirs. Its presence impacts subsurface formation evaluation and porosity calculations. Thus, the investigation of these nodules was carried out using: core image analysis; thin sections petrography; micro computed tomography (MicroCT) scans; bulk rock X-Ray Diffraction (XRD); sulfur & strontium isotope analyses. Where core was unavailable, geochemical data and resistivity-based image logs were used to expand the anhydrite characterization to derive field wide distributions.

Bulk rock XRD and thin section-based petrographic studies indicate that the mineralogy of the study sandstones is dominated by quartz (>90%), with minor clay, and the presence of variable amounts of localized anhydrite as diagenetic nodular cements. The habitat of anhydrite nodules displays a substantial size variation, with nodules ranging from millimeters to several centimeters in scale. The larger nodules are easily identified visually in core samples and on borehole image logs. To investigate the origin of the anhydrite, sulfur and strontium isotope analysis were used to understand the relative timing of the nodule's development within the paragenetic sequence.

Results from the sulfur and strontium isotopic analyses are consistent with the understanding that the anhydrite nodules are a late stage emplacement. A semi-quantitative "Anhydrite Abundance Index" (AAI) was calculated across key wells within the fields to establish the anhydrites regional distribution. The AAI uses the dry weight fraction of calcium and sulfur from geochemical logs to determine the volume of anhydrite. These volumes were further calibrated to volumes obtained through geochemical analysis of core samples, which is key to calculating the correct anhydrite volume required for formation evaluation. Regional distribution mapping created from this volume data suggests a widespread presence of the anhydrite nodular cementation.

Understanding the relative abundance of anhydrite volumes is important when investigating the reservoir quality, especially if underestimating its presence may affect log-based porosity calculations and subsequently permeability calculations. The in-place quantification of the anhydrite nodular cement in 1D also enabled research to further the understanding of post-depositional, geochemical and geographic controls on the subsurface modelling and reservoir quality prediction.
An Evaluation of Pressure Control Methods During Riser Gas Handling with MPD Equipment Based on Transient Multiphase Flow Modeling and Distributed Fiber Optic Sensing
Authors: Wei Chen , Chen Yuanhang , Santos Otto , Kunju Mahendra , Mahmud Shahriar , Almeida Mauricio , Sonnemann Paul
Published: September 2022

During the past decade, the increased use of Managed Pressure Drilling (MPD) equipment has significantly improved the safety and efficiency of gas influx management. However, it is still not clear to the industry what should be the safest and most effective pressure control method for removing gas influxes out of a riser. The objective of this study is to perform a systematic evaluation of different pressure control methods for riser gas handling, including the constant surface backpressure method, the constant riser bottom pressure method, and the fixed choke and constant outflow method.

A transient multiphase flow simulator based on a Drift Flux Model was developed to simulate riser gas handling events in a Water Based Mud (WBM) system. Multiple sets of full-scale experimental data were used for the calibration and validation of the simulator. In the full-scale experiments, riser gas events were simulated by injecting gas into the bottom of an experimental well, followed by applying different pressure control methods. Besides conventional downhole and surface pressure and flow measurement instrumentations, a Distributed Fiber Optic Sensing (DFOS) system was used for the high-resolution monitoring of gas influxes in the annulus.

The performance of different pressure control methods was evaluated based on the simulation results, including the behaviors of surface and riser bottom pressures, peak surface outflow rates, and the time required for riser gas handling. The numerical simulations carried out in this study can help better understand the different pressure control methods and improve the design of riser gas handling strategies.
Case Study: Enhanced Compression Pumps with Mixed Flow Stages for Unconventional Shale Plays
Authors: Martinez Villarreal Paola , Escobar Patron Katherine , Rosales Ballesteros Eder
Published: September 2022

The challenges of unconventional reservoirs have driven electric submersible pump (ESP) providers to continue making improvements to the mechanical design of the pump stages. These improvements enable covering wider operating flow ranges and maximizing production without the need to replace the artificial lift system with a different method such as gas lift or rod pumps.

In 2016 and 2020, two new pump types were introduced as a solution for unconventional wells. This case study summarizes the results of the analysis of 52 ESPs installed with the new pump types in the Midland Basin from 2019 to 2021 for a leading operator in the basin. The operator's well test data showed a declining production averaging from 1,300 to 100 BFPD, with water cut from 40% to 99% and gas-oil ratios up to 9,000 SCF/STB.

This paper presents the results of how the re-engineering of a standard mixed-flow stage becomes a solution to improve the performance of the ESPs when producing from unconventional shale plays where the downhole environment is extremely harsh. The re-engineering of the standard mixed-flow stage produced a stage characterized by high hydraulic performance and superior efficiency. The study's conclusions can also be applied to conventional shale plays with more benign conditions.

To develop the new stages used in the two new pump types, an engineering team conducted an extensive study considering the available run life data and the results of the top failure modes of the ESPs when operating at low flow ranges in unconventional wells. The engineering team considered a stage design to optimize the operation in the low-flow-rate region by a better distribution of downthrust and stress management of the pump's internal components.
Electronic Data Captured at Bit is Utilized to Improve Drilling Practices and Performance in Laterals
Authors: Lepe Juan Pangtay , Anderle Seth , Anderson Victoria , Greene Allen , Lane Tyler , Grandstaff Brad
Published: September 2022

When drilling laterals, the horizontal portions of an unconventional well, one of the primary unknowns has been how much weight and torque is effectively being transferred from surface to bit, and how that affects performance. The introduction of high-frequency vibration, motion, and strain sensors integrated into the drill bit has yielded new insights into drill bit behavior. This paper presents a recent field study, in which these downhole measurements were utilized to develop a solution for improving drilling performance in the lateral section.

Operators often use computer-controlled "auto-driller" settings, either weight on bit (WOB) or rate of penetration (ROP) mode, to drill through lateral sections. While higher instantaneous ROP can be achieved by using WOB mode, it can create inconsistent performance, thus, leading to dysfunctions.

In this case, a high resolution, at-bit vibration, motion, and strain sensor was introduced to characterize dysfunctions and drill bit behavior in the interval of interest. Data was captured during multiple drilling modes across multiple wells to conduct an engineering analysis and determine appropriate drilling practices to enhance drilling efficiency.

The same drill bit equipped with the at-bit sensor was used to drill two lateral intervals with the same target formation in the same well pad. Both lateral runs made it to total depth (TD) in a single run.

During the first run, overall higher dysfunctions (axial and lateral+torsional) were observed when WOB mode was used in contrast to ROP mode. Therefore, for the next run, ROP mode was recommended along with a higher ROP setting. The same consistent vibration levels were observed but at an overall higher ROP, while also improving the drill bit's dull condition.

When drilling in WOB mode, spikes in downhole WOB were observed on connections when tool joints would pass through the rotating head. However, this was not shown on surface WOB measurements.

When cross-plotting differential pressure and torque-on-bit, a gradual decrease in torque was observed throughout the run with similar differential pressure indicating a loss in drilling efficiency.

As a result, when applying the optimized drilling practices learned from these runs using the innovative at-bit sensor, a 20% overall ROP increase and dull conditions improvement were observed.

This paper describes how novel features were placed in an at-bit sensor capturing continuous 1,024 Hz data to visualize dysfunction, motion, and strain downhole, and to determine the effect of drilling practices, and how they are related to drilling performance, leading to recommendations that improve performance. Detailed field data from different runs, in which revised drilling practices helped manage dysfunctions and enhance overall drilling performance, will be presented.
Injection of Flue Gas Improves CO2 Permeability and Storage Capacity in Coal: A Promising Technology
Authors: Vega-Ortiz Carlos , Panja Palash , McPherson Brian J. , McLennan John D.
Published: September 2022

Swelling of coal thus reducing permeability is the main detrimental for any carbon dioxide (CO2) capture and storage (CCS) projects. Additionally, CO2 capture from flue gas or direct air is an expensive process. The current commercial simulators are impaired of combining various effects such as fluid segregation, adsorption, Darcy's flow, and permeability change in coal. The objective of this study is to develop a numerical model to simulate flue gas injection in coal. The study is motivated by encouraging preliminary results from lab-scale experiments of injection of flue gas (ideally a mixture of Nitrogen and CO2) in coal.

Bench-scale experiments demonstrated the swelling reduction caused by the selective flow of surrogate flue gas N2-CO2 mixture, based on the fluid stratification at sub-critical conditions where the density of pure components in a vertical container causes stratification as predicted from the Grashof number and the thermodynamic properties of fluids. The numerical simulation aims to reproduce and upscale the results from bench-scale Darcy experiments performed in subbituminous coal flowing pure species and mixture of CO2 and N2 at in-situ conditions. A thorough review of the material balance equations coupled with geomechanical stresses and adsorption mechanisms is observed and implemented in a Newton-Raphson model.

The stratified fluid in the vertical column is injected in batches onto the coal sample at reservoir conditions producing a cyclic flow of CO2-rich mixture, followed by a N2-rich phase. The repetitive cycles of batch pumping of the stratified CO2-N2 mixture allow the periodic adsorption and desorption interactions, maintaining a high permeability compared to the reduced flow of pure CO2 and the CO2 adsorption in the coal matrix regulated by its partial pressure. Pure CO2 flow in coal resulted in a permeability reduction from 3 to 0.1 mD. The novel optimized CO2-N2 mixture flow ensures an average permeability of 2 mD, while preserving 70% of the maximum CO2 storage capacity.

Carbon dioxide storage (CCS) in a suitable geologic setting such as unmineable coal seams are getting research attention for fighting global warming. The model provides important guidelines for the optimization of CO2 capture storage (CCS) in coalbed based on novel strategy of flowing a surrogate flue gas N2-CO2, minimizing the coal swelling due to the adsorption mechanisms, and consequently maintaining a high permeability, while ensuring adsorption and consequently permanent storage of CO2.

The proposed methodology offers not only to improve permeability of coal, but also considers the possibility of injecting flue gas mixtures from combustion processes, reducing considerably the cost of surface facilities for CO2 treatment prior to injection. The successful implementation of this technology could potentially solve the problem of global warming at a low-cost process of injection and storage of CO2.
Fluid-Pipe Interaction in Horizontal Gas-Liquid Flow
Authors: Porter Kyle , Pereyra Eduardo , Mesa Jose , Sarica Cem
Published: September 2022

In recent years, internal, two-phase, flow-induced vibration (FIV) has received elevated attention in various fields while assessing piping system fatigue life. Regarding the oil and gas industry, in particular, assessing FIV impact is essential for ensuring the integrity of flow lines, both onshore and offshore.

This study conducted a series of experimental tests at various superficial gas and liquid velocities to investigate the effects of flow parameters on the structural dynamics of a horizontal 6-inch ID polycarbonate test section. The relationship between flow characteristics and the structural response was examined in detail. A novel methodology was developed and implemented to achieve non-intrusive, simultaneous measurement of pipe motion and liquid distribution.

The presented results reveal that downward deflection generally decreased with increasing superficial gas velocity and increased with increasing superficial liquid velocity. It was also found that as superficial gas velocity increased, the range of frequencies experienced by the test section increased, with increased participation from higher frequencies in the range. Film and slug body liquid holdups are strongly related to the observed deflection amplitudes.
Team Coaching in Oil and Gas
Authors: Solway Martin Edward
Published: September 2022

With teams becoming a more critical element, tasked to deal with ever changing scenarios, while operating in increasingly complex environments, this research looks at the role of team coaching in the oil and gas industry. Whether it is being used today and how as an intervention it can help with the current and future challenges the industry faces.

The research was centred around answering three questions:

Where is team coaching being used today in the oil and gas sector and how effective has it been on increasing team performance? What challenges or desires does the industry have, where team coaching could help? How can the industry more widely adopt and implement effective team coaching?

Solway (2021)

To help answer the questions posed, data was collected from a range of sources including a questionnaire and interviews with Human Resources Leaders, Business Leaders, and Coaches (Solway, 2021). Public third-party data was used from the main coaching bodies. The findings suggested a significant percentage of the participants have used team coaching in some form. However, apart from senior leadership teams, other team-based activities such as team facilitation were found to be the predominate form of intervention, perceived as team coaching (Solway, 2021).

Three themes emerged from the findings. These included a need for defining what is team coaching and how it can add value to the oil and gas industry; identification of some of the key challenges where team coaching can potentially help; and a focus on operations and how team-based activities are used today (Solway, 2021). An industry specific definition for Team Coaching was offered, along with a team coaching model, specific to oilfield operations teams.
A Deep Learning Formation Image Log Classification Framework for Fracture Identification – A Study on Carbon Dioxide Injection Performance for the New Zealand Pohokura Field
Authors: Katterbauer Klemens , Qasim Abdulaziz , Al Shehri Abdallah , Al Zaidy Rabeah
Published: September 2022

We have presented a new deep learning framework for the detection of fractures in formation image logs for enhancing CO2 storage. Fractures may represent high velocity gas flow channels which may make CO2 storage a challenge. The novel deep learning framework incorporates both acoustic and electrical formation image logs for the detection of fractures in wellbores for CO2 storage enhancement and injection optimization. The framework was evaluated on the Pohokura-1 well for the detection of fractures, with the framework exhibiting strong classification accuracy. The framework could accurately classify the fractures based on acoustic and electrical image logs in 98.1 % for the training and 85.6 % for the testing dataset. Furthermore, estimates of the fracture size are strong, indicating the ability of the framework to accurately quantify fracture sizes in order to optimize CO2 injection and storage.
Validation of a Novel Beta Diversion Design Factor for Enhancing Stimulation Efficiency Through Field Cases and Near Wellbore Diversion Model
Authors: Almulhim Abdulrahman , Khan Abdul Muqtadir , Hansen Jon , Alobaid Hashem , Emelyanov Denis
Published: September 2022

The design of fracture diversion in tight carbonates has been a challenging problem. Recently, a conceptual and theoretical workflow was presented using a β diversion design parameter that uses system volumetric calculations based on high-fidelity modeling and mathematical approximations of the etched system. A robust field validation of that approach and near-wellbore diversion modeling was conducted to extend the application.

Extensive laboratory and yard-scale testing data were utilized to realize the diversion processes. Fracture and perforation modeling coupled with fracture diagnostics was used to define system volumetrics, defined as the volume where the fluid needs to be diverted away from. Multimodal particulate pills were used based on a careful review of the size distribution and physical properties. Bottomhole reactions and post-fracturing production for multiple wells and 100 particulate pills were studied to see the effect of the β factor on diversion and production performance. A multiphysics near-wellbore diversion model was used for the first time to simulate the pill effect.

Representative wells were selected for the validation study; these included vertical and horizontal wells and varying perforation cluster design, stages, and acid treatments. A complex problem was solved with reaction modeling coupled with near-wellbore diversion for the first time based on given lithology and pumped volumes to match the treatment and diversion differential pressures. Final active fractures and stimulation efficiency were computed through etched geometry. The results showed a range of etched fracture length from 86 to 109 ft and width of 0.05 to 0.08 in. A similar approach was used for perforation system analysis. Diversion pills from 2 to 15 per well were investigated with a 5- to 12-bbl particulate diversion pill range. Finally, the β factor was calculated for each case based on the diversion material and system volumetric ratio. The parameter was plotted against the average diversion pressure achieved and showed an R2 of 0.87. Based on the comprehensive theoretical, numerical modeling, and field-coupled findings, a β factor of 0.8 to 1.0 is recommended for optimum diversion and production performance. For multiple cases, stimulation efficiency and production performance have been enhanced up to 200%.

From the field results, it is evident that the design of near-wellbore diversion needs to be strategic. The unique diversion framework provides the basis for such a well- and reservoir-specific strategy. Proper and scientific use of diversion material and modeling can lead to advances in overall project management by optimizing the cost–efficiency–quality project triangle. Digital advancements with digitized cores, fluid systems, and advanced modeling have significant potential for the engineered development of tight carbonates.
The Importance of Early Investments in Local Content: Lessons Learned from Guyana's Enterprise Development Centre Five Years in
Authors: Scott Susan , Gaskin-Peters Natasha
Published: September 2022

Enterprise Development Centres (EDCs) have emerged as a best practice in building local content and capacity and driving economic development in emerging economies. In 2017, prior to Final Investment Decision (FID) of any oil field, ExxonMobil Guyana launched the Centre for Local Business Development (The Centre) in Guyana, managed by DAI Global. This early investment was key to show ExxonMobil's commitment to optimizing local content. The Centre's early mission was to build local competitiveness and support Guyanese businesses in accessing opportunities in the emerging oil & gas sector through capacity building, training, awareness and education.

This paper looks at lessons learned five years into the operation of the Guyana Centre for Local Business Development. The objective is to help identify learnings that can be shared with other similar institutions and economic development programs to support implementation of successful strategies especially in relation to supply chain development. This paper focuses on the evolving mission of the Centre from training towards more mentorship of the local supply chain and the process of this evolution and lessons learned along the way. Further, the paper will use empirical findings over the last five years to show the importance of early investments in the supply chain and how this helps to support a growing and evolving economy.
What's the Best Way to Stabilize Oil in the Permian? An Examination of Different Facilities Layouts
Authors: Chan Isabel , Baaren Sander , Sarcletti Anthony
Published: September 2022

Operators in the unconventional shale oil space are becoming increasingly focused on methods to reduce emissions, mitigate issues due to NGL production, increase sales oil production, and increase safety. Moreover, for facilities to operate unmanned facility designs are required to be simple and robust.

Each facility configuration optimizes for a different utility: some allow more flexibility for the economic investment, while others offer familiarity of operation. The option that adds the most flexibility per dollar invested focuses on low-pressure separation with simultaneous heat introduction with minimum necessary storage tanks.

Three different facilities are compared utilizing hydrocarbon recovery, NGL production, gas production, compression power, and Reid Vapor Pressure as key metrics. The three layouts include: a heater treater, a vapor recovery tower, and a novel elevated heated separation design that combines the utility of a heater treater and vapor recovery tower.

The novel low-pressure stabilization system allows for stabilized oil to be pumped either to storage tanks or directly to the custody transfer point. Emissions stemming from tank vapor and tank vapor management systems are avoided as the oil is stabilized before entering the storage tanks or being transported directly to custody transfer.

The novel system can be scaled for higher production rates seen at central processing facilities where traditional equipment such as heater treaters would require operating several parallel production trains. The novel design avoids known operational safety and maintenance issues regarding direct fired heaters and tanks; thus, improving safety and operational cost.

Existing facilities designs include equipment such as direct fired heater treaters, inline heat exchangers, vapor recovery towers and tanks. The results from all process simulations and operational data is summarized in an overview comparing the performance of the various facility designs.
A Semi-Analytical Model for Water Injection Wells in Tight Reservoir Considering the Multi-Dynamic Closure Phenomenon- Case Studies in X Oilfield, China
Authors: Wang Zhipeng , Ning Zhengfu , Guo Wenting , Cheng Qidi , Wang Wuchao , Li Gexuan , Wang Yang
Published: September 2022

It is well known that waterflooding will induce fractures. The extensive direction, length, and conductivity of the induced fractures will largely determine the performance of producing wells. The quantitative characterization of the fractures can help prevent water breakthrough in time. This paper proposes the waterflooding-induced dynamic fracture model (WIDF) to monitor the fracture half-length at any time and extend the stable production period. The rock mechanics principles are applied to characterize the dynamic extension and closure of fractures during water injection and build-up periods. The model was solved using the point source function approach. The phenomenon of multi-dynamic closure causes the fluid to be squeezed several times, creating a storage effect and a non-constant conductivity within the fracture. Experimental results show that the conductivity of water injection-induced fracture follows an exponential function. Finally, Duhamel's principle was used to couple the pressure response of the wellbore and the fracture. The field case is shown in the paper to verify the accuracy and practicality of the WIDF model. Multi-peak appears in the pressure derivative curves. The actual data match well, and the parameter values obtained are close to the actual values. However, the conventional finite-conductivity model treats pressure response data with multiple peaks as incorrect values. This behavior will result in the length of dynamic closed fracture being ignored and the interpreted fracture half-length being smaller than the actual value. Misidentification of fracture lengths will affect the determination of reasonable injection volumes and even cause producing water early, which can severely impact the performance of production wells. The storage effect caused by multiple dynamic fracture closures reasonably explains the significant storage effect obtained by the conventional model. The WIDF model enables researchers can monitor induced fracture half-length at any time, allowing them to take measures in time. The model has been successfully applied to the X oilfield in China and has significantly improved the performance of injection wells and increased the stable production period of production wells. The fluid compressed by dynamic fractures reasonably explains the significant storage effect in injection wells. The identification and interpretation of multiple dynamic fracture closure phenomenon make us obtain more accurate fracture half-length parameters, which monitors and suppresses the occurrence of water breakthrough effectively and help researchers take measures to increase the stable production period of production wells.
Micro-Continuum Approach for Modeling Coupled Flow and Geomechanical Processes in Fractured Rocks
Authors: He Xupeng , AlSinan Marwah , Zhang Zhen , Kwak Hyung , Hoteit Hussein
Published: September 2022

Coupling flow with geomechanical processes at the pore scale in fractured rocks is essential in understanding the macroscopic processes of interest, such as geothermal energy extraction, CO2 sequestration, and hydrocarbon production from naturally and hydraulically fractured reservoirs. To investigate the microscopic (pore-scale) phenomena, we propose an efficient and accurate flow-geomechanics coupling algorithm to advance the fundamental flow mechanism from the micro-continuum perspective. Further, we investigate the stress influence on fluid leakage caused by matrix-fracture interaction. In this work, we employ a hybrid micro-continuum approach to describe the flow in fractured rocks, in which fracture flow is described by Navier-Stokes (NS) equations and flow in the surrounding matrix is modeled by Darcy's law. This hybrid modeling is achieved using the extended Darcy-Brinkman-Stokes (EDBS) equations. This approach applies a unified conservation equation for flow in both media (fracture & matrix). We then couple the EDBS flow model with the Brown-Scholz (BS) geomechanical model, which quantifies the deformation of rock fractures. We demonstrate the accuracy of the coupled flow-geomechanical algorithm, in which the accuracy of the EDBS flow model is validated by a simple case with a known analytical solution. The BS geomechanical model is demonstrated with experimental data collected from the literature. The developed flow-geomechanical coupling algorithm is then used to perform sensitivity analyses to explore the factors impacting the fluid leakage caused by the matrix-fracture interaction. We found that the degree of fluid leakage increases as matrix permeability increases and fractures become rougher. Fluid leakage degree decreases with the increase of inertial forces because of the existence of eddies, which prevents the flux exchange between the matrix and fracture. We also investigate the stress influence on fluid leakage and further on fracture permeability under the impact of matrix-fracture interaction. We conclude the fracture permeability would increase with the consideration of the fluid leakage and exhibits an exponential relation with the effective stress.
Multiscale Carbonate Rock Reconstruction Using a Hybrid WGAN-GP and Super-Resolution
Authors: Zhang Zhen , Li Yiteng , AlSinan Marwah , He Xupeng , Kwak Hyung , Hoteit Hussein
Published: September 2022

The X-ray micro-Computed Tomography (μ-CT) is the primary tool for digital rock imaging, which provides the foundation for numerically studying petrophysical properties of reservoir rocks at the pore scale. However, the finite resolution of μ-CT imaging cannot capture the micro-porosity at the sub-micrometer scale in carbonate rocks. The tradeoff between the resolution and field of view (FOV) is a persisting challenge in the industry. The machine-learning-based single-image super-resolution techniques has rapidly developed in the past few years. It is becoming a promising approach to "super-resolve" low-resolution carbonate rock images. In this study, we present a fast super-resolution generative adversarial network to enhance the image resolution of carbonate rocks. A pre-trained VGG network is implemented to extract important high-level features, from which the perceptual similarity is evaluated between the generated and ground-truth images. The novelty of this study is two-fold. First, the generator is significantly simplified with a fast super-resolution convolutional neural network. On the other hand, the spatial and channel squeeze-and excitation block is applied to recalibrate nonlinear feature mapping so that the quality of super-resolved images is promising even with much fewer residual blocks.

To quantify the quality of the super-resolution images, we compare difference maps between the generated and ground-truth images. Numerical results indicate that the proposed network shows excellent potential in enhancing the resolution of heterogeneous carbonate rocks. In particular, the pixel errors are minor, and the super-resolution images exhibit clear and sharp edges and dissolved mineral texture. This study provides a novel machine-learning-based method using a simple generative adversarial network with squeeze and excitation blocks to super-resolve μ-CT images of carbonate rocks.
Integrated Oil Companies and the Quest for Energy Transition
Authors: Alsuwailem Majed , Williams-Rioux Bertrand
Published: September 2022

Integrated oil and gas (O&G) companies operate vertically integrated businesses that span the O&G value chain. In this way, they can leverage expertise across multiple domains rather than just focusing on exploration and production (E&P). Examples of such companies include British Petroleum (BP), Cenovus Energy, Chevron, Eni, Imperial Oil, ExxonMobil, Repsol, Royal Dutch Shell, Suncor Energy and TotalEnergies. Integrated O&G companies played a central role in advancing energy availability and economic growth during the twentieth century. However, these companies now face the challenge of addressing the need for a new energy transition in the twenty-first century. This transition will involve a shift from fossil fuels to alternative fuels, such as renewable wind and solar energy, battery storage and nuclear energy.

The extent to which these efforts will impact integrated oil companies (IOCs) and their assets depends on the global community's commitment to reducing demand for hydrocarbons. In the extreme, these companies may go out of business. Efforts by IOCs to adapt their business models will also affect their viability. Thus, IOCs face an important choice that will define their role in the energy transition. On the one hand, they can observe the energy transition without participating. Potential repercussions of this choice include lost business and investments and increased financial penalties in the form of carbon pricing. On the other hand, they can play an active role in the energy transition by committing to decarbonize the industry. For example, they can invest in carbon capture, utilization and storage (CCUS) and explore geothermal energy. They may incorporate solar and wind power and move toward a low-carbon hydrogen economy.

In summary, this study investigates the role of IOCs in the next major energy transition. The key points are as follows:

IOCs were leaders of the 20th century energy transition to oil. However, they are now the incumbent players in the industry and face a prisoner's dilemma in responding to the transition to green energy. IOCs have been replaced by national oil companies (NOCs), independent operators and oil field service companies (OFSCs) as major suppliers and drivers of innovation. The integrated business models of IOCs can adapt to new business practices. However, IOCs tend to lack flexibility in implementing new business practices compared to independent companies. Innovation for the energy transition requires new entrants and specialized operators, such as OFSCs, to take the lead. To respond to uncertainties around climate regulation and shifting investor sentiment, IOCs can seek partners in climate coalitions, such as the Oil and Gas Climate Initiative (OGCI), targeting cooperation. Strategic advantages in reservoir management can be used to advocate for CCUS as a decarbonization service for IOCs’ downstream consumers.
Building Up Steam, A Progressive Approach to Drilling Volcanic Geothermal Formations
Authors: Roberts Sion Llywelyn , Bailey Michael James , Victor Pawl , Sutan Mada , Prasetia Bagus , Lock Ellie
Published: September 2022

There are several challenges for polycrystalline diamond compact (PDC) drill bits when drilling through volcanic and interbedded applications. Roller cone (RC) bits have historically been used in geothermal applications. However, low rate of penetration (ROP), bearing life, and repairability limitations have halted progress in performance and economic gains. This paper presents game-changing PDC technology that addresses the limitations of previous conventional drill bits in a challenging geothermal application.

A reimagining of drill bit body geometries, the latest in shaped cutter technology, and durable backup elements were lab tested and customized on an unconventional drill bit chassis to maximize ROP, improve durability, and reduce downhole torque variation. The initial design phase focused on identifying and overcoming these key challenges. The second phase was to field test the new drill bit in the target application and compare it to offset runs, including roller cone, hybrid, and conventional fixed cutter bits. Key performance indices such as ROP, durability, steerability torque generation/variation, and cost per meter (CPM) were considered when evaluating the new design's performance.

Initial testing in the 16-in. section showed promising results in the field. Higher-than-average ROP and excellent interval resulted in the lowest cost per meter run. In addition, the drill bit complemented the bottomhole assembly (BHA) design well, as minimal effort was needed to keep the trajectory as planned. The delta torque generation was lower than conventional PDC bits whilst displaying higher ROP than roller cone alternatives.

The improved durability of the new design also allowed it to be run multiple times without repair, which was not possible with previous bits due to bearing hours or durability issues. This was always a challenge through the volcanic formations seen in this application. In remote locations that do not have facilities to repair drill bits, the ability to run multiple times without the need to repair is critical. The operator saved costs by not needing to transport the bit and repair any PDC cutters or secondary components after multiple runs. This outstanding run validated the benefits of the new design in terms of both technical and economic perspectives.
Does the Chow Pressure Group Analysis Provide Any New Information in the RTA of Unconventional Reservoirs?
Authors: Shekhar Jha Himanshu , Lee W. John
Published: September 2022

This study presents a thorough mathematical analysis of Chow Pressure Group (CPG) for unconventional reservoirs exhibiting characteristic power-law behavior and demonstrates that the CPG analysis yields the same results that traditional rate transient analysis (RTA) provides using the log-log plot between rate-normalized pressure (RNP) vs. material balance time (MBT) and Cartesian plot between RNP and timen, where n is the flow exponent. CPG analysis was proposed for flow regime identification, power-law decline-curve analysis, predicting long-term well performance from choked-back wells, and evaluating long term performance changes associated with offset frac hits. Our work shows that the presence of fracture skin may impair the CPG analysis results, while in absence of fracture skin, CPG analysis leads to the computation of the same model parameters as a standard RTA.

Our study examined the expression used to calculate CPG and shows that its formulation is closely related to β −derivative (d log(RNP)/ d log(time)). We show that the power-law model does not take fracture damage into account, and this could disguise the actual start of a flow regime resulting in a poor estimation of b−value and other model parameters using CPG. We demonstrate that the Bourdet derivative is not affected by fracture damage and leads to a more definitive flow regime identification. We further explain the CPG analysis model parameters in terms of the Wattenbarger type curve parameters for a simpler and more meaningful interpretation of the reservoir and fracture properties. We validate our hypothesis using field production data from an unconventional reservoir.

Our work presents a thorough mathematical analysis of the CPG and shows that it computes the same model parameters as standard RTA in absence of fracture damage. In presence of fracture damage, CPG could show a significant delay in identifying a unique flow regime and may result in poor estimation of b-value and other model parameters. We found that the Bourdet derivative is less sensitive to fracture damage and should be used for a more definitive flow regime identification. We recommend using CPG analysis as a complementary tool to traditional methods such as Arps decline-curve analysis for RTA of production data.