bluuebunny/crossref_metadata_2025 huggingface dataset:
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

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

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

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

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

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

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

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.
Increasing Production Capacity of a Low Resistivity Pay Reservoir Associated with a Highly Flooded Environment in a Fault Corridor – A Successful Case History from UAE Onshore
Authors: Khemissa Hocine , AL Jaber Sulaiman S. , Al Suwaidi Ayesha Eid , Singhal Sangeeta , Chang Ernesto Lenin B. , Al Mesafri Ahmed Saif , Thakur Parmanand D. , Mumtaz Asim , Potshangbam Sanathoi , Hameed Mahmoud , Saravanakumar Krishnan
Published: February 2024

Maximizing reservoir exposure in a low resistivity pay reservoir located in a fault corridor along the flank of a brownfield is tremendously challenging. Additionally, the high uncertainty associated with two uneven types of waterfronts, in the form of water slump/reverse conning and front water moving along the planned wellbore, poses a risk of derailing the well objective and compromising well performance. It was critical to consider the right application to mitigate these challenges to achieve the well objective. Considering the subtle log responses in the reservoir, the only differentiating parameter to consider for well placement with confidence was the resistivity changes within the reservoir. The variation in resistivity was either related to saturation differences or lithological units.

Mapping the resistivity profile around the wellbore and defining the reservoir properties would be possible by utilizing a tool with a greater depth of detection integrated into a conventional triple combo Bottom Hole Assembly (BHA). Extra Deep Azimuthal Resistivity (EDAR), with its lower frequencies and flexible spacing between transmitter and receiver, delivers the required large Depth of Detection (DOD). This measurement was considered to provide the required saturation and bed boundaries solution. Mapping the changes in resistivity above and below the well path facilitated informed well placement decisions to maximize reservoir contact and navigate within the optimum resistivity of the reservoir.

Utilizing the EDAR application in this well proved to be highly beneficial in placing the well in the oil column of this low resistivity pay reservoir. It mapped the water slumping intervals from the above unit and the change in water level from below the well path. It mapped two faults that displaced the well from its original primary target to the upper secondary target. Based on the boundaries mapped, the throw of the faults was estimated, and the well bore position was established. The EDAR inversion mapped an increase in water saturation from both the top and bottom. Based on this information, total depth (TD) was declared ~400 ft earlier than planned. The intervals of water slumping and elevated water zones below the trajectory were considered when optimizing the lower completion designs.
Drilling Anomalies Identification Using Near Bit Vibrations
Authors: Iufriakova A. , Bukhanov N. , Golikov P. , Bakulin A.
Published: February 2024

Various anomalies while drilling are a major hazard both for safety and economic efficiency. Additional measurements combined with Bayesian approaches allow to identify anomalies and their precursors with high accuracy. In this work, we utilize a high-frequency accelerometer located downhole with Bayesian networks to avert twist-off events.

Statistical analysis was performed to identify the most effective method to train the structure of Bayesian network. It was demonstrated that the usage of K2 score-based algorithm produced the most favorable results. Moreover, the model's performance was further enhanced by incorporating domain expertise at the learning and validation stages. The results indicated significant improvement in the performance of the model, with increased accuracy and faster processing speed. Our study achieved an F1 score of 0.84 for the task of anomaly identification. The results of the proposed approach are in good agreement with those obtained by unsupervised machine learning techniques (based on an isolation forest and principal component analysis).
First Utilization of the Shaped Point Loading Edge Cutters Technology to Enhance the Drilling Performance and Steerability of Long Directional Section
Authors: Alqarafi Abdulaziz , Almomen Hassan , Marhoon Qasim
Published: February 2024

One of the main objectives in directional drilling operations is finding ways to optimize the drilling performance and directional work. Drilling and geo-steering through dense and soft Carbonates layers introduces various challenges such as low rate of penetration, high near-bit vibrations and steerability. To overcome these challenges, a shaped edge polycrystalline diamond compact (PDC) cutter technology was introduced.

The shaped edge PDC cutter technology employs a point loading chamfer on the diamond tip of the PDC cutter for efficient load distribution on the cutter edge and more weight transfer to smaller portions of the drilled rock. The state- of-the-art cutter technology is developed to increase the bit stability and rock destruction efficiency while drilling through highly interbedded and hard formations.

In addition to the new PDC bit design and the in-depth analysis and formation specific parameters roadmap, an optimization process comprising rotary steerable system (RSS) bottom-hole assembly (BHA), enhanced trajectory design, drilling fluids and system hydraulics design and subsurface geomechanics modelling were introduced to optimize the drilling performance and drill the vertical, curve and lateral section in one run.

The proposed shaped edge PDC bit design in addition to the optimization roadmap delivered multiple consecutive sections with an exceptional performance without reported steerability challenge. Each section is almost 10,000 ft long, drilled through interbedded carbonate formation capped with dense and soft layer. The average rate of penetration (ROP) improved by 33% compared to the previous PDC technology. With respect to drilling the soft curve interval, the new PDC bit design succeeded to enhance the ROP, overcome the steerability concern and reduce the near-bit vibrations by 33% while eliminating the surface stick-slip vibrations. The implementation of the optimization methodologies helped achieving new performance records in the most challenging drilling environments. The new bit design established greater ROP response over the conventional cylindrical edge PDC cutters while improving the overall stability and steerability of the drilling system.

The evolvement of the cutter edge showed substantial outcomes in terms of penetration rates, bit stability, and total cost savings by overcoming the drilling challenges and reducing the number of trips required to drill to total depth (TD), thus reducing the overall well delivery time.

The optimization roadmap, job execution, and post well evaluation results that helped to expand the cutter technology in other bit sizes and frames which are presented in this paper including a discussion on the key challenges met during the planning and the execution phases.
Enhancing Drilling Efficiency with Flanked Non-Planar Shaped PDC Cutters
Authors: Suleiman A. , Roberts S. , Bailey M. J. , Doudou S. , Hallal A. , Perez J.
Published: February 2024

This paper examines the performance of a novel Flanked Non-Planar (FNP) shaped Polycrystalline Diamond Compact (PDC) cutter through laboratory and field testing in challenging applications. Testing results demonstrate significant advantages of the new cutter shape, which are further validated by an extensive field test program in the Middle East. The geometry of the PDC cutter has emerged as a crucial factor in enhancing fixed-cutter drill bit performance industry-wide. Two types of cutters were investigated: a V-shaped FNP and a non-V-shaped FNP cutter. Both cutters had identical non-planar geometry on the face but varied in cutter-rock interaction characteristics. Field evaluations compared these cutters with legacy cylindrical cutters in terms of drilling efficiency, durability, repairability, and cost per foot. Laboratory tests assessed drilling efficiency at single cutter and full-scale drill bit levels. Field testing involved more than 470 runs across the Middle East, using offset runs with legacy cylindrical cutters for comparison.

Laboratory tests revealed significant benefits of FNP cutters. The non-V-shaped FNP cutter reduced vertical force by 20% due to its angled flank, which improved cuttings evacuation and decreased frictional losses. The V-shaped FNP cutter showed a 30% reduction in vertical force and enhanced fracture propagation with its tip geometry. Full-scale tests demonstrated a rate of penetration (ROP) improvement of 13 to 38% for the non-V-shaped FNP drill bit across different formations, while the V-shaped FNP drill bit achieved a 29 to 40% ROP improvement.

Field trials in the Middle East across various conditions showed ROP improvements of 14 to 112%, with the highest gains in shales and carbonates using the V-shaped FNP cutter. Cutter durability was comparable to conventional round cutters, considering the interval drilled and dull condition. Moreover, a cost analysis considering bit cost, ROP, and rig rates demonstrated significant reductions in cost per foot compared to offset runs. Overall, the novel FNP cutters offer tangible drilling efficiency gains that significantly reduce drilling costs. This paper highlights the significance of exploring innovative shaped PDC cutter designs and their impact on drilling efficiency. It demonstrates that FNP cutters improve efficiency at both micro and macro levels. Field testing confirms that these novel geometries provide tangible ROP performance and drilling cost reduction without compromising durability or repairability.
Simulation of ultrasonic Doppler System for Drilling mud Flow Measurements
Authors: Zharnikov T. , Ryabova A. , Dobrovolskii I. , Katterbauer K.
Published: February 2024

Mud flow monitoring is essential for safe drilling and formation characterization. During coiled tubing drilling, drill cuttings are not available for direct observation and measurement. The purpose of the study is to investigate the feasibility of determining the size of the solid phase from spectra obtained by ultrasonic Doppler measurement, as well as determining the velocity of solid particles in the drilling fluid. For this purpose, numerical simulation is used with the ultrasonic measurement described using a meshless method, while the flow is simulated using a finite volume method. The developed model makes it possible to obtain spectra for various particle size distributions of the solid phase and flow characteristics, such as flow rate and viscosity. As a result, the dependence of the average signal amplitude on the concentration of solid particles in the drilling fluid was determined. Its analysis shows that the measurement in question can be used to estimate the average particle size.
Off-The-Shelf IoT Gateways as a Viable Alternative to Traditional HMI Devices
Authors: Mohamed A. , Almuhdi T. , Rahamtallah M. , Ghizawi N. , Louiz A. , Elsheikh K. O.
Published: February 2024

The modern industrial landscape is evolving rapidly, emphasizing digitalization and real-time monitoring and control. Human Machine Interface (HMI) devices have become a cornerstone in meeting these needs, facilitating seamless interaction between human operators and machines. However, the recent surge in demand for HMI devices comes at a time of heightened global supply chain issues, making getting these devices challenging for many organizations. Moreover, there is an increasing demand for added functionalities, such as enhanced analytical capabilities, driven by the need to improve decision-making processes and increase operational efficiency.

The current disruptions in the supply chain are causing delays and shortages of specialized hardware, such as HMI devices. This scarcity is due to a lack of essential components for HMI device manufacturing, resulting in limited availability. The impact extends to many industries where HMI devices monitor and control complex processes. As a result, there is an urgent need for alternative solutions to address the immediate shortage while maintaining operational efficiency and minimizing disruption to established workflows.

Considering the challenges above, we propose utilizing off-the-shelf Internet of Things (IoT) gateways as a viable alternative to HMI devices. With their standard and more available hardware components, IoT gateways offer a level of availability and ease of integration that can potentially address the current challenges faced in procuring HMI devices. Moreover, the proposed solution aims to not only restore the HMI functionalities but also enhance them by offering additional features.
Optimization of Fluid Lab Testing for Conventional Proppant Fracturing Applications in HT Reservoirs
Authors: Yudin A. , Farouk M. , Al-Jalal Z. , Nurlybayev N. , Jalil R. , Klyubin A.
Published: February 2024

Fracturing operations in low to medium permeability reservoirs tend to be driven by efficiency and costs of the operations. At the same time, fracture geometry and conductivity need to be optimized to ensure economical field development. The objective of this paper is to revise and enhance fluid design lab testing process in high-temperature (HT) reservoirs by dealing away with fluid over-designing practices through accurate fracturing modeling which will significantly reduce reservoir damage.

Fluid design practices often assume a safety factor for the fluid exposure duration to be equal to or greater than the full treatment duration. It is also commonly required to match the bottom hole static temperature (BHST) for the whole lab test duration with a minor focus on the overall tubulars and reservoir cooldown during later stages of the treatment. The advanced planar 3D simulator was used to create sensitivity studies for the temperature profile inside the fracture during placement. Results were then used in the experimental lab testing to optimize the fluid recipe based on new temperature profile and time of exposure.

Advanced software modeling and rheological studies identified several ways to avoid fluids overdesign, leaving behind cleaner reservoirs without imposing operational risks. The sensitivity analysis revealed that depending on several parameters such as the fluid leak-off severity, volume, and rate of the treatment; the amount of polymer load can reach 30% and higher when accounting for the cool down effect and reduced fluid exposure time. For the fluid breaking ability at lower temperatures, it is also critical to mimic realistic temperature profile inside the fracture for several hours after the treatment. The studies suggest that the largest impact is expected for extreme HT conditions in relatively higher permeability and prolific formations with fluid efficiency values of 40% and lower. These reservoirs will require a significant amount of pad to compensate for leakoff and considerable amount of proppant to cover the entire interval. In these cases, maximum fluid exposure will be limited by 50-70% of the entire treatment time and the cool down effect prior to proppant entry will be considerable. Considering middle eastern applications, this type of reservoir is not a minor number of cases; hence the new methodology would be beneficial to consider and implement across the region.

This paper will reveal an optimized approach to the fracturing fluids lab testing and will help to shape the future of fracturing treatments in HT reservoir conditions in a way that will not only reduce the fracturing cost but will also help to reduce reservoir damage hence improving well productivity.
Simplified Power-Law Model for the Material Balance of Gas Reservoirs Experiencing Water Influx
Authors: Hosseinpour-Zonoozi N. , Blasingame T. A.
Published: February 2024

A simple power-law model is presented for performance of gas reservoirs experiencing water influx using only cumulative production, reservoir pressure, and the gas deviation factor (i.e., the z-factor). The application of the model provides estimation of gas-in-place. The gas material balance relation including ONLY water influx is given in dimensionless form as: pzD=(1−GpD)(1−WeD)  where: pzD=p/zpi/zi WeD=weBWGBgi GpD=GpG

The following empirical model is proposed for dimensionless water influx function (WeD): WeD=aGpb+1

Substituting this model into the gas material balance yields: pzD=(1−GpD)(1−aGpb+1)

The proposed power-law water influx model was exhaustively validated using the Carter-Tracy and Van Everdingen-Hurst methods to simulate water influx and pressure-cumulative gas production behavior for an unsteady-state water-influx system. The results of these simulation cases were fitted using the proposed (empirical) power-law water influx model and for every case that was tested, the proposed model gave an essentially perfect correlation of the simulated reservoir performance behavior.
Cluster Spacing Effect on the Fracture Interference Including Stress Shadow
Authors: Ibrahim Ahmed Farid
Published: February 2024

Over the last decade, the application of horizontal drilling and multistage hydraulic fracturing has significantly impacted shale formations, achieving economic productivity through the creation of expansive fracture surfaces. Determining the optimal cluster spacing in shale gas wells is a complex task, contingent upon the unique geological characteristics of each formation. While a closer spacing between clusters can enhance gas recovery, it escalates drilling and completion costs, compounded by stress shadow effects on fracture propagation.

This research introduces a comprehensive workflow to investigate the impact of cluster interference on well performance. Commencing with a fracture propagation model, accounting for stress shadow effects due to the same injected slurry volume, we integrated analytical rate transient analysis (RTA) with reservoir numerical simulation to assess the effective fracture surface area for hydrocarbon production. The effective fracture surface area from RTA to the actual stimulated fracture area from numerical simulation ratio was then correlated to cluster spacing.

Findings reveal that higher stage numbers and tighter cluster spacing result in increased cluster interference, yielding a low effective to actual fracture surface area ratio and heightened stress shadow effects, hindering fracture propagation. Conversely, widening cluster spacing, with a constant injected proppant volume, boosts the effective to actual fracture surface area ratio and diminishes cluster interference. Optimal spacing, based on formation properties, was identified as 6 clusters per stage with 33 ft spacing. This research provides valuable insights for completion and reservoir engineers, aiding in the optimization of cluster spacing to maximize well revenue.
Novel Methods for Simulating Reservoirs with Tilted Fluid Contacts
Authors: Kashinath A. , Jayasinghe S. , Dow E. , Middya U. , Dogru A. H.
Published: February 2024

This paper introduces two new approaches for modeling reservoirs with tilted fluid contacts. We first introduce a method based on local capillary pressure adjustments, which uses adjustments of the capillary pressure near the oil-water contact to ensure that the contact surface does not move during production. The second approach uses hydrodynamic aquifer flow to support the oil-water tilt. A non-linear inverse problem is solved to determine the parameters that control the aquifer flow. Both approaches are implemented in a parallel reservoir simulator and applied to a synthetic reservoir case.
Advanced 3D Dynamic Model for Forensic Investigation of Reservoir Connectivity in Heterogeneous Systems
Authors: Al-Obathani O. H. , Rahman N. M. Anisur
Published: February 2024

Quantifying the magnitude of pressure communication and characterizing reservoir properties among the wells are the key objectives of pressure interference tests. In this study, we will shed light on how to plan for a multi-well pressure interference test in a tight, heterogeneous carbonate reservoir with dynamic model. Then, we will explain the capabilities of the dynamic model to characterize reservoir properties especially between the wells where the uncertainty is high due to a lack of inter-well measured data.

This study describes a multi-well, interference test design and analysis procedure for a tight carbonate reservoir for the purpose of developing an injector-producer pattern strategy. This subject test has been performed utilizing three wells. An active producer located in-between two shut-in injectors. These shut-in injectors have been equipped with high-resolution gauges to detect the pulses created by the active well. For accurate interference test results, we have constructed 3D dynamic model based on a high-resolution geological model. This model has been utilized as a platform to characterize the reservoir properties by matching the model output with test data.

With this approach, we have successfully quantified the magnitude of hydraulic communication between the producer and each of the two injectors. Moreover, reasonable match results of the dynamic model with the pressure interference data has been achieved. With this quality match, a good understanding of heterogeneous reservoir properties between the producer and each of the injectors has been attained. In fact, the magnitudes of pressure communication between the producer and each of the injectors in addition to the reservoir transmissivity and storativity become the foundation of any future production-injection strategy as part of the development plan. Moreover, the interference test results can be incorporated into the full simulation model to enhance the quality of the model.

This study demonstrates the value of utilizing 3D dynamic models for a multi-well interference test design and analysis. With this approach, the outcomes of the interference test, such as, magnitude of hydraulic communication, transmissivity, and storativity between the wells, impact the future development plan. Hence, reservoir engineers will have the upper hand in optimizing the production strategies as well as future developments.
Breaking New Ground: Novel Lithology Estimation Machine Learning Model for Pulsed Neutron Logging Technology
Authors: Turkey S. , Elias M. , Gamal H. , Ikande P.
Published: February 2024

The rapid advancement of machine learning techniques has opened up new possibilities for improving lithology estimation for outstanding reservoir characterization. This study introduces a groundbreaking machine learning model specifically developed for lithology estimation utilizing measurement data from Multi-Detector Pulsed Neutron (MDPN) logging.

Traditional methods of lithology estimation have relied on limited data inputs, and non-automated interpretation leading to significant uncertainties and inconsistencies. On the other side, the proposed machine learning model is considered as an automated approach that is trained over well-log big data combined with high-computation advanced artificial neural networks algorithm. The model undergoes extensive data preprocessing and analytics, feature engineering, training and optimizing the model architecture/parameters, and model evaluation workflow.

By leveraging the power of artificial intelligence, the proposed model is qualified to learn/capture the data pattern interrelationships between pulsed neutron logging measurements and lithology variations that enhance the accuracy and efficiency of lithology estimation in diverse geological formations. The developed model was evaluated with statistical metrics to assess the prediction accuracy for the model outputs versus log data measurements. The evaluation of the model's performance demonstrates that superior artificial neural networks technique has outstanding capability to accurately estimate lithology with an accuracy higher than 97% with low loss error evaluation metrics. The successful application of the model in a case study conducted in a Middle East region further validates its effectiveness and robustness.

The integration of this innovative machine learning model with pulsed neutron logging technology offers a transformative solution to automate lithology estimation workflows in the oil and gas industry. This research paves the way for enhanced lithology characterization, leading to improved decision-making in reservoir evaluation and exploration activities.
Real-Time Stick-Slip Mitigation Using Combined Machine Learning and Physics Based Techniques
Authors: Yahia Hana , Romary Thomas , Gerbaud Laurent , Menand Stephane , Mahjoub Mohamed
Published: February 2024

Downhole vibrations can lead to significant drilling problems in unconventional wells, such as frequent tool failures that increase drilling costs. Detecting these vibrations during drilling is crucial for enhancing drilling practices. One of the most destructive types of downhole vibrations is torsional stick-slip, characterized by fluctuations in bit rotation speed between zero and several times the surface rotation speed. Typically, surface data is used for real-time diagnosis of this drilling dysfunction. In recent years, Artificial Intelligence (AI)-based detection algorithms have increasingly been proposed in the literature. However, a key drawback of AI methods is their limited applicability to wells in the same field with similar geological formations and bottom-hole assemblies (BHAs). This paper aims to address this limitation and explore solutions for generalizing these approaches. It does so by employing transfer learning techniques and the inclusion of physics-based features. Using historical offset well data, this paper presents trained and tested machine learning models capable of predicting the stick-slip severity index (SSI) using sequences of surface measurements and physical features. This model can be deployed in real-time on drilling rigs to provide diagnostics and recommendations. In addition to that, the paper proposes a real-time auto-updated stability heatmaps, using the trained regression model and surface measurements while drilling, to help the drillers choose the optimal drilling parameters to avoid stick-slip vibrations.
Natural Gas Sweetening Using Ternary Blend of MEA, DEA and PZ: Energy, Exergy, CO2 Emission Analysis, Sensitivity Analysis and 2 Level Full Factorial Design
Authors: Sornumpol R. , Maneeintr K. , Prathana Nimmanterdwong P.
Published: February 2024

This study pioneers an advanced exergy analysis approach to evaluate the energy and exergy dynamics of natural gas sweetening. Focusing on a ternary blend of Mono Ethanol Amine (MEA), Di Ethanol Amine (DEA), and Piperazine (PZ), the research aims to enhance understanding of process exergy. The investigation encompasses energy, exergy, sensitivity, and a 2-level full factorial design, aiming to refine natural gas while reducing environmental impact. The study employs Aspen HYSYS V10 to model the Acid Gas Removal Unit (AGRU), with specified operational parameters. The absorption and regeneration columns, heat exchanger, cooler, pump, and valves are key components analysis. Sensitivity analysis highlights the crucial influence of parameters such as reflux ratio, circulation flow rate, lean amine molar flowrate, lean amine temperature, and lean amine pressure inlet. Findings underscore the significance of optimizing these factors for efficient sweetening. Notably, increasing the reflux ratio enhances CO2 capture efficiency, albeit with increased energy regeneration requirements. The type and concentration of solvent used significantly influences regeneration energy demand. The lean amine temperature and pressure also play crucial roles in the efficiency of the sweetening process. ANOVA results confirm the statistical significance of circulation flow rate and lean amine pressure inlet, underscoring their impact on CO2 capture efficiency. The study establishes the optimal conditions for achieving high CO2 capture efficiency with minimal regeneration energy demand. Exergy analysis reveals that the regenerator unit accounts for the highest destruction rate, followed by the heat exchanger and cooler. This analysis provides valuable insights for optimizing the amine-based CO2 absorption-desorption capture processes. In summary, this research offers a comprehensive exploration of advanced exergy analysis for natural gas sweetening using a ternary amine blend. The findings provide valuable insights for refining natural gas processing with reduced environmental impact, advancing sustainable energy technologies, and promoting more responsible fossil fuel utilization.
Natural Fracture Characterization Through Digital Outcrop Model in Southwestern Saudi Arabia Geothermal Field
Authors: Arrofi Daffa , Abu-Mahfouz Israa S. , Rafiq Jawad , Cline Jarvis R. , Al-Jafari Mutaz , Al-Ghamdi Mohamed
Published: February 2024

Geothermal energy is the heat energy stored in the subsurface of the Earth due to the decay of radioactive elements within the mantle and the crust (Schubert et al., 1980). This energy is continuously produced, making it a sustainable and renewable energy source (Owusu and Asumadu-Sarkodie, 2016). One of the key advantages of geothermal energy is its capacity to provide baseload power that can be run constantly to fulfill the energy demands of any society, making it a dependable and persistent source of energy. Unlike other renewable energy sources such as solar and wind, geothermal energy, it is not affected by weather or daylight and can supply a consistent source of electricity day and night.

Saudi Arabia possesses significant geothermal resources along of western boundary for both volcanic and non-volcanic geothermal systems (Chandrasekharam et al., 2014; Lashin et al., 2014; Al-Douri et al.,2019; Abu-Mahfouz et al., 2023). One of the potential geothermal areas is in Jizan, Southwestern Saudi Arabia (Hussein et al., 2013; Chandrasekharam et al., 2016; Arrofi and Abu-Mahfouz, 2023). Despite the fact that Jizan has a medium-high enthalpy system, it is largely underutilized. One of the most prevalent challenges encountered during exploitation is a low permeability reservoir to allow fluid circulation. However, it can be addressed by undertaking a detailed study of characterizing natural fractures both in the surface and subsurface.

Natural fractures might enhance fluid circulation and permeability, making geothermal extraction a more viable option (Arrofi et al., 2022; Viswanathan et al., 2022; Abu-Mahfouz et al., 2023). It is crucial to investigate the distribution, orientation, and connectivity of fractures in geothermal systems. In the Al-Ardah geothermal field, located in Jizan, hydrothermal fluid is believed to flow from the eastern region, following the dip direction of the regional faults, and discharge on the western side (Arrofi et al., 2023). The reservoir area is indicated to be in the eastern region of Al-Ardah within the granitic rock (Fig. 1). Additionally, the granitic rock in the Al-Ardah area had undergone significant alteration due to intense interaction with the thermal water (Lashin and Al Arifi, 2014). It also suggests that the reservoir is located in the eastern part of the hot springs area. This study aims to characterize fractures and investigate fluid flow in the eastern part of Al-Ardah, Jizan, using an outcrop analogue (see the study location in Fig. 1).