bluuebunny/crossref_metadata_2025 huggingface dataset:
Limitations and Fallacies of Carbon Capture and Storage (CCS) and Impact on Oil and Gas Production
Authors: Farouq Ali S. M. , Soliman Mohamed Y.
Published: October 2023

Carbon Capture and Storage (CCS) euphoria is turning the oil and gas operations upside down, without having any perceptible impact on atmospheric carbon dioxide (CO2) that continues to increase. It is intended to show that the current CCS regimen has serious technical and fiscal constraints, and questionable validity. Carbon Capture, Storage, and Utilization (CCUS) is also discussed briefly.

There is ample data to show that the CO2 concentration in the atmosphere is unrelentingly increasing, and the annual global CCS is about 0.1% of the 40 billion tonnes emitted. As much as 30% of the carbon dioxide captured is injected/re-injected into oil reservoirs for oil production and is not CCS at all. Several CCS methods are being tested, and some are implemented in dedicated plants in the world. A number of impediments to CO2 capture are identified and limited remedies are offered. It is shown that the problem is so gigantic and has so many dimensions that limited solutions have little efficacy. For example, about one-half of the world's population lives at less than $5 a day and has no recourse to CCS technologies.

Major facets of the CCS problem are: (1) Validity of the future atmospheric CO2 concentrations based on the 100+ climate models for global warming. This is not the main discussion but is touched upon. (2) Impact of the desired CO2 concentrations on coal, oil, and gas production. (3) Principal CCS methodologies, including Direct Air Capture. (4) CCS vis-à-vis carbon tax, carbon credits, and carbon trading. (5) CCS subsidies – Is CSS workable without subsidies? At this time, No. The current tax credits for CCUS do not make sense. Finally, attention is given to CCS on a world scale – showing that so long as the great disparities in the living standards exist, CCS cannot be achieved to any significant level. All of the above is seen against the backdrop of oil and gas production and achieving Net Zero.

It is shown that globally CCS has not increased beyond ∼0.1% of the global CO2 emissions in the past 20 years. The problem is that in CCS, there is injection only, no production! The paper offers partial solutions and concludes that oil and gas will continue to be energy sources far beyond the foreseeable future, and oil companies will accomplish the needed CSS.
Increase of CO2 Storage in High-Salinity Carbonate Reservoirs by Foam Injection
Authors: Pang Jieqiong , Mohanty Kishore
Published: October 2023

Oil and gas reservoirs are being considered for CO2 storage for reducing greenhouse gas emission from industrial activities. CO2 flooding in carbonate reservoirs often suffers from poor sweep efficiency due to unfavorable mobility ratio, gravity segregation, and reservoir heterogeneity. This study aims to evaluate foam flooding as a method to improve CO2 storage in a high temperature, high salinity carbonate reservoir. Several surfactants and nanoparticles were examined to identify the most effective foam formulation. Foam stability at the reservoir temperature and ambient pressure was used first to screen suitable foaming agents. The chosen foaming agents were then foamed at the reservoir temperature and pressure and their stability was observed in both the absence and presence of crude oil. Next, the foam mobility was measured through a core at 80% quality with selected foaming agents. Finally, CO2 flood and CO2-foam flood experiments were performed in carbonate reservoir cores under reservoir conditions. Many surfactants and nanoparticles exhibited instability at the high salinity and temperature conditions of this study. Based on the results of foam stability tests at the ambient pressure, a nonionic surfactant and two zwitterionic surfactants were chosen for further study. Through foam stability tests and rheology tests at the reservoir pressure, the most effective foam formulation was identified to be a combination of the nonionic surfactant Aspiro S 2410 and the nanoparticle EOR 12-V3. The addition of nanoparticles significantly increased the half-life of the foam at reservoir pressure. The presence of crude oil had a detrimental effect on CO2-foam stability. The apparent viscosity of the CO2-foam decreased as the flow rate increased, and the surfactant-nanoparticle foam exhibited higher apparent viscosity compared to the foam generated by the surfactant alone. Furthermore, core flood experiments demonstrated that foam flooding with surfactant-nanoparticle solution achieved higher incremental oil recovery and CO2 storage capacity compared to both CO−2 flooding and foam flooding with surfactant alone. In conclusion, the surfactant-nanoparticle formulation developed in this study shows promise as a CO2 foaming agent for use in high-salinity, carbonate reservoirs.
Experimental Evaluation of Lactic Acid for Matrix Acidizing of Carbonates
Authors: Bettencourt Greyson Soares , Zhu Ding , Hill A. D. , Kamman Chad
Published: October 2023

To improve efficiency of standard HCl stimulation treatments, many alternative acid systems have been developed to mitigate corrosion, increase wormhole efficiency, and divert fluids for better acid coverage. However, these alternative systems come at a price compared to HCl which is cheaper and sufficient in most applications.

Lactic acid is an organic acid that is less corrosive and has reduced reactivity compared to HCl. The advantage and application of lactic acid has not been studied extensively like other alternative acids. To evaluate lactic acid as a viable alternative acid system, we conducted a series of linear core flood matrix acidizing experiments using 40 weight percent lactic acid at two temperatures over a range of injection rates. The goal was to characterize the wormholes created by lactic acid and identify the appropriate condition that lactic acid can outperform HCl. Core flood tests were also conducted at high temperature and lower concentrations to observe change in behavior and performance.

Lactic acid performance was analyzed by comparing pore volumes to breakthrough (PVbt) with previous HCl experiments. Lactic acid was found to be more efficient than HCl at injection rates below optimum for 40 %. At the lower temperature of 150 °F, lactic acid maintained similar PVbt over the range of injection rates.

Wormhole geometry from CT imagery and pressure response data was studied to identify unique characteristics or behavior lactic acid may have. CT images of lactic acid generated wormholes reveal a geometry versus injection rate relationship that is contrary to the conventional understanding of wormhole growth patterns. Images show extensive branching in most low injection rate tests. The results are characterized as appearing to have self-diverting behavior. Pressure differential data across the core shows pressure drop increases in nearly every experiment. For the lower concentration tests, pressure differential increase was not observed for 10 % and 20 % and only occurred at 30 % lactic acid. Precipitation occurred during and immediately after most high temperature experiments and after the 30 % test which is suspected to be plugging permeable channels. Further investigation may provide more insight into the unique capabilities of a simple yet overlooked acid system.
Proppant Flowback Prevention and Control by Analysis of Early Time Well Production Data
Authors: Pandey Vibhas J.
Published: October 2023

Proppant flowback during the post-stimulation well clean up and production is a common occurrence in most hydraulically fractured wells. Whilst some proppant is expected to be produced during the well cleanup operations that typically follow the treatment execution, the long-term production of proppant can be problematic from an economic viewpoint. A thorough analysis of early time production data can be used to develop guidelines that can aid in minimizing the proppant flowback and associated issues.

It is a well-known fact that the production of the proppant from a propped fracture is related to the forces acting on the proppant pack during the well that is actively producing fluids. Some of these, e.g., increase of effective stresses on the proppant, are stabilizing in nature, whereas others related to inertial flow from fluid velocity, viscosity and others can destabilize the pack. Most proppant flow back related studies associate the proppant production with critical flow velocities that are prevalent for given flowing conditions. This important parameter is thus a key to predicting proppant production during the well's producing life. In this study, flow rate and pressure data collected during the post-treatment flowback activity is used in simulating bottomhole (BH) production rates with the help of calculations. Using Gaussian solution scheme, the BH rate is distributed amongst the various perforation clusters while incorporating the effects of key hydraulic fracture characteristics in presence of simulated effective bottomhole flowing pressures across each fluid entry point into the wellbore. The solution is updated at each time step during the simulation. The production allocation is then used for calculation of effective flow velocities which are then compared with critical velocities to determine if proppant production can occur. Steps to mitigate or reduce the flowback, if present, are then recommended based on the analysis.

In the flowback model developed during the study, flowing bottomhole pressures at each sleeve depth was generated with the help of hydrostatic and frictional pressures, and used in forward calculation of total flow rate at downhole conditions. The bottomhole flowrate was then allocated across various sleeves and finally, the associated production fluid velocities were calculated. These were compared with critical velocities corresponding to the fracture associated with each of the sleeves (or perforation set) to determine if there was potential of proppant flowback under the prevailing conditions.

The procedure developed in the study can help in diagnosing conditions that may lead to proppant flowback and thus aid in preventing it by adjusting the controllable parameters during the treatment design and production phase. This technique can be easily implemented on similar completions worldwide.
Horizontal Well Design to Optimize CO2 Sequestration and Oil Recovery in the Permian
Authors: Gang T. , Jones A. , Bandyopadhyay P. , Tovar F. , Bealessio B.
Published: October 2023

This paper presents a reservoir modeling study about positioning horizontal wells to optimize carbon sequestration and oil recovery simultaneously in the Wasson field, which is one of the largest reservoirs in the Permian Basin with 6 billion barrels of original oil in place. A significant portion of this field has been under CO2 injection for enhanced oil recovery for decades, so the CO2 gathering, processing, and distribution network in the area makes the Wasson area extremely cost-competitive as a CO2 storage site. Transitioning the source of CO2 injected in the Wasson area from natural to anthropogenic has the potential to sequester hundreds of millions of metric tons of carbon in the coming decades. Although the traditional development strategy has achieved attractive economic returns in the better-quality rock, novel well configurations are needed to be economically successful as development is expanded to areas with lower rock quality.

We used a compositional, history-matched reservoir model to perform a sensitivity study of lateral section length, horizontal orientation, spacing, and vertical placement for both production and injection wells. We also studied the vertical placement of the wells with respect to the main oil column (MOC) and the residual oil zone (ROZ), a distinctive characteristic of the Permian Basin. In all the scenarios, the MOC is to be co-developed with the ROZ. Since our focus was on the lower-quality rock areas, we selected horizontal wells due to their success in the cost-effective development of tight reservoir rocks. The significant remaining greenfield potential in the Wasson area offers an opportunity for a complete revolution of the development strategy from vertical to horizontal wells.

The most important finding of this study is that the vertical placement of the horizontal injector has a significant effect on oil recovery and lifecycle CO2 retention. Placing the injector close to the bottom of the ROZ and the producers in the MOC resulted in the highest carbon sequestration. The optimized case improved CO2 sequestration by 40% over the base case. The absence of significant vertical flow barriers in the area, along with our prior understanding of the reservoir heterogeneity and CO2 phase behavior, enabled us to optimize well placement to take advantage of gravity drainage. This configuration exposed a larger section of the reservoir volume to the injectant, resulting in a higher sweep efficiency.

Our work provides relevant guidance on the design of future developments using horizontal wells to optimize carbon sequestration and incremental oil recovery simultaneously during CO2 EOR and carbon capture, use, and storage (CCUS) projects. These findings are likely to lead to technical and economic success, even in the poor rock quality areas in the Wasson reservoir, significantly increasing the sequestration and oil recovery potential of this field.
Machine Learning Assisted Petrophysical and Geochemical Reservoir Description Integrating Multi-Scale Well Data
Authors: Xu Chicheng , Jin Yuchen , Lin Tao , Li Weichang , Alzayer Yaser , Ibrahim Zainab
Published: October 2023

Qualitative visual observations of depositional and diagenetic features in core are routinely recorded by geoscientists for geological environment interpretation and reservoir characterization. Quantitative core plug measurements that are typically acquired from laboratory often results in spatially discrete data points. This work applies image analysis and machine learning (ML) workflow to develop continuous reservoir property profiles along the cored interval capitalizing on both discrete core measurements and core visual characteristics.

We introduce a ML assisted workflow that converts core photos into continuous quantitative features that can be integrated with routine core analysis and well logs for integrated reservoir characterization. Visual rock types (VRT) and their associated properties can be predicted based on the quantitative attributes of core photos such as color, brightness, and texture variations by using ML algorithms such as k-means clustering and support vector machine.

We applied the workflow to characterize unconventional reservoirs based on multi-scale well data from the Eagle Ford Shale USA including core photos, core gamma ray, core plug measurements of petrophysical and geochemical properties, and well logs. Inclusion of quantitative, continuous, and high-resolution image attributes significantly enhanced the accuracy of both facies classification and total organic carbon (TOC) prediction. The accuracy of both classification and regression outperformed the benchmark that only used well log data which proves its practical value in reservoir characterization. Successful prediction of reservoir properties from core photos can lead to increased data coverage and resolution to enhance reservoir characterization and reduce the cost associated with destructive tests.
A Novel Approach to Predict Hydrodynamic Forces Using a Mechanistic Model for Pseudo-Slug Flow
Authors: Garcia C. , Sondermann C. Nogueira , Pereyra E. , Sarica C.
Published: October 2023

Pseudo-slug flow is a flow pattern for flow-induced vibration (FIV) applications owing to high force amplitude, which could cause fatigue on pipes and fittings subject to gas-liquid conditions. FIV prediction requires understanding the unsteady nature of the two-phase flow, particularly the structure velocity. A comprehensive analysis of datasets published in the literature with a wide range of diameters, inclinations, fluids, and flow conditions was conducted. Based on the data collected and previous studies in the literature, it was identified that the structure velocity of pseudo-slug flow is often found to vary between the linear velocity of slug flow and the wave celerity in segregated flow. Dimensionless parameters are proposed to calculate the structure velocity, while the flow behavior is modeled with Zhang et al. (2003) unified model and used as input for the new model. The proposed approach predicts structure velocity for pseudo-slug and churn flow, considering slug pressure contribution and dimensionless velocity. With a more accurate calculation of the structure velocity, improving the prediction of hydrodynamic forces for fatigue analysis is possible.
New Technology Reduces Carbon Emissions from Natural Gas Compression and Production Facilities
Authors: Guoynes John , Stiles David , Vail Cory , Stiles Robert , Kreuz Terry , Pritchard Gary , Nolen Craig , Schmitt Joshua
Published: October 2023

Natural gas compression contributes significantly to greenhouse gas (GHG) emissions, emitting nearly 10% of the total carbon dioxide equivalent per year from the Oil & Gas industry sub-sector1. The most common method of reducing GHG emissions from compression currently involves converting to electric drive2. Electric drive is not a preferred fuel source with most compressor operators because it can be expensive, difficult to acquire at field sites, and it can place new demands on existing power supply grids. A new chemical-free process has been developed with a small footprint to capture exhaust from natural gas drive compressors and supporting gas-fueled production equipment. The process separates carbon dioxide (CO2) and nitrogen from exhaust allowing the CO2 to be discharged at high pressure for transport, sequestration, or enhanced oil recovery (EOR). GHG emissions are significantly lowered from compression while permitting operators to maintain their preferred natural gas fuel source.

The patented process3 treats high volumes of exhaust, up to 70 million scf/D, containing CO2, nitrogen, and water. It incorporates innovative technology for carbon capture including a unique rotary separator design to remove water and centrifugally separate CO2 from exhaust gas. Advanced moving wall compressors and moving wall expanders have been developed to regulate system pressures and temperatures to values necessary for separation and discharge of supercritical CO2. The system is mounted on a small skid allowing for easy placement at typical production and midstream sites.

Technical and economic results of the system are presented, demonstrating that high-quality carbon dioxide is captured, separated, and pressurized for disposal or commercial use without the use of large equipment. This paper presents details of the process with initial test results and how it can be used on thousands of oil and gas production, midstream, and transmission sites. The exhaust gas stream is processed after lowering the temperature, then water is removed, and CO2 is separated from nitrogen without chemicals. The design lowers GHG emissions from all internal combustion engines, turbines. and supporting production equipment. The CO2 produced from this technology can be greater than 99% pure and meets IRS guidelines using 45Q tax credits for carbon sequestration.4

The oil and gas industry has a long history removing CO2 from gas streams.5 The novel technology presented incorporates new and practical solutions for oil and gas operators to reduce their GHG Scope 1 and Scope 2 emissions while maintaining their preferred natural gas fuel source at their midstream, transport, and production sites.
Flare Reduction Through Aquathermolysis Process Control in Heavy Crude Oil Field
Authors: Al Fazari M. , Hinai A. , Ghefeili H. , Rashdi A. , Mahrezi D.
Published: October 2023

Petroleum Development Oman LLC (PDO) is Oman's premier oil producer and operates several fields at "A". "A" East and "A" West are located on the eastern flank of the South Oman Salt Basin. As "A" Thermal fields contain heavy oil, PDO plans to significantly increase oil recovery by increasing the steam injection which is having high energy intensity.

The objective of this paper is to demonstrate the improvement in Flared Gas reduction resulted in reduction in Green House Gases (GHG) emissions.

This work had been initiated after noticeable increase in Associate gas flaring in AP Flare system. High GOR wells has been surveyed and closed to control the flare resulted in oil deferment, however the flaring was still increasing. Many challenges faced including casing vent, PCV passing, increasing in steam injection (Aquathermolysis Process) and flare gas metering.

In this project, lean practices were used to define the opportunities including A SIPOC (suppliers, inputs, process, outputs, customers) diagram, Process Mapping, Cause & Effect Diagram, Root causes analysis, and development of Visual Management Boards (VMB), standard operating procedures (SOP) to sustain Improvements.

Practical Problem Solving (PPS) and Kaizen approaches were used, and several countermeasures had been completed leading to reduce in Associate gas flaring by an average of 50%, equivalent to (∼ 2 million USD/annum).

This project had been completed with minimum spend on capex. By doing these modifications, it resulted in below benefits (confirmed):

GHG Reduction of 30K TCo2e/yr due to reduction of Flared gas in and utilization for Boiler Fuel Gas. An oil secure of 10% of total "A" production due to maintaining the processing Gas in /out of the Facility. A cost saving of more than 2 mln$ / annum due to the utilization of gas for other process.
Effect of Quick Salinity Variations in Virtual Meter Applied on Water Injection Wells
Authors: Parisi S. , Ursini F. , Vignati E. , Quattrocchi S.
Published: October 2023

Real Time Virtual Flowmeter (RTVFM) is a key digital technology for real time monitoring of well performances, for both production and injection wells. The main advantage of this tool is to provide estimations of well flow rates, based on wellbore pressure drop, using real-time (RT) pressure and temperature data measured by gauges installed in the well. This paper focuses on the effects of water properties on RTVFM application to water injection by evaluating their impact on the dynamic gradient and its implication in the rate estimation.

Injected water can be a mix of different sources: sea water, fresh water, formation water and produced water. As a result of these different contributions, it is common to observe variations of salinity even on an hourly basis. A variation of water salinity impacts on density and viscosity, therefore changing the dynamic gradient. Salinity in injected water is commonly measured by sampling analysis, thus providing data with a much lower frequency than RT gauges. As a result, it is not usually possible to integrate salinity variation into the standard RTVFM workflow, leading to significant errors in the rate estimation. The innovative workflow presented in this paper, named Virtual Salinity, calculates water salinity in real time in wells equipped with reliable flowmeters. It regresses the dynamic gradient equation on salinity values. The results of this workflow improve the quality of RTVFM application to other wells injecting the same water mix. At each timestep, virtual salinity values are used to evaluate the correct pressure gradient for RTVFM calculation.

The workflow has been successfully tested on a deepwater offshore asset, to prove its reliability. The Virtual Salinity has been applied on an offshore injection network: three wells injecting a mix of produced and sea water. The workflow, applied to all injectors, generated consistent salinity profiles. A reference virtual salinity profile has been used as an input for RTVFM simulations. For all of the injectors, RTVFM reproduced the independent flowmeter measurement with enough accuracy.

The innovative methodology here presented provides a key tool to monitor salinity of injected water and can be used in field where injected salinity is not measured, providing a valuable information at minimal costs. Water salinity is one of the main inputs of production data analysis, that allows to maximize reservoir knowledge and consequently final recovery. Moreover, the greater accuracy of Virtual Meter rates significantly improves the injection monitoring, thus supporting an effective reservoir management.
Combined Experimental and Well Log Study of Anisotropic Strength of Shale
Authors: Zheng Danzhu , Miska Stefan , Ozbayoglu Evren , Zhang Jianguo
Published: October 2023

Organic-rich shales have been contributing significantly to gas production in the US, led by new developments in horizontal drilling and hydraulic fracturing techniques. Shales have been known to be the source of wellbore instability problems in drilling processes. In the past practice, shales were treated as isotropic for mud window calculation and trajectory design. However, organic-rich shales are anisotropic due to their laminated structure and chemical properties. Thus, it is vital to theoretically and experimentally investigate the anisotropic strength of shale.

This study aims to evaluate the anisotropic mechanical properties of shale by tri-axial tests and predict anisotropic shale properties by well-logging data interpretation. Shale mechanical properties (Young's Modulus, Shear Modulus, and Poisson's Ratio) of different bedding plane orientations (0/ 45 / 90 degrees) were studied. Both compressive strength and tensile strength were investigated in different directions. A simple Plane of Weakness and Modified Cam Clay failure criteria were applied to describe the shear failure mechanism.

Well logging data were used to connect experimental data and actual field data. Compressional wave velocity was predicted with different inclination angles by stiffness parameters. The predicted compressional wave velocity for a 45-degree inclination angle perfectly fits the field logging data. Experimental data indicated the mud window for a particular shale formation.

This study provides an understanding of shale anisotropic strength of different bedding orientations and instructions on safety mud window calculation for directional drilling through shale formations.
A Recurrent Neural Network-Based Solvent Chamber Estimation Framework During Warm Solvent Injection in Heterogeneous Reservoirs
Authors: Ma Z. , Yuan Q. , Xu Z. , Leung J. Y.
Published: October 2023

Warm solvent injection (WSI), injecting low-temperature solvent into formations to reduce the viscosity of heavy oil, is a clean technology for heavy oil production while reducing greenhouse gas emissions and water usage. The success of WSI operation depends on the uniform development of solvent chambers in reservoirs. However, reservoir heterogeneity stemming from shale barriers plays a detrimental role in the conformance of solvent chamber development and oil production rate. In this work, we develop a novel recurrent neural network (RNN)-based framework with the capability of efficiently tracking and estimating the solvent chamber positions in heterogeneous reservoirs based on only production time-series data. The developed estimation model utilizes the "sequence-to-sequence" mapping methodology to correlate observed production time-series sequence and solvent chamber edge sequence via a long short-term memory (LSTM) algorithm. The developed RNN-based workflow is tested via several cases, and the results are promising. The predicted dynamic solvent chamber locations match the corresponding true locations with a high coefficient of determination and a low mean squared error. The major benefits of this workflow include reducing time for numerical simulations and saving overall monitoring and tracking costs for conventional techniques. The present work would provide a good illustration of the capability of practical integration of machine learning methods in solving engineering problems.
Nano-Surfactant Packages for Enhanced Oil and Gas Recovery in Hydraulic Fracturing-Impact on the Nano-Sizers on the Performance of Conventional Surfactants
Authors: Kakadjian Sarkis , Flowers Amanda , Kitchen Jarrett , Gebrekirstos Amanuel , Boyd Kristopher , Algadi Otman
Published: October 2023

Surfactant packages have been known to enhance the post-treatment clean-up of stimulation treatments from hydraulic fracturing. When used this way, the surfactant packages are known as flowback aids. These additives reduce the completion fluid loss from the fracture surface to the formation by assisting the return of trapped fluids in the wellbore and reservoir to the surface. Nano-surfactant packages have also been reported to create somewhat their equivalent mechanism of performance and benefit to the application. The current work shows the development of flowback recovery aids based on Nano-Surfactant packages from currently used surfactant technology and their actual impact in the Permian when compared both technologies within the same formation.

Nano-Surfactants have been formulated with current surfactant packages by the introduction of nano-sizers. The performance of the different formulations have been evaluated by different methodologies including monitoring the changes on the size of the micelles by light scattering. Those formulations that once diluted in brackish and/or produced water showed size of the micelles below 100 nanometers (nm), were then rated by interfacial tension with crude oils from Wolfcamp formations. Over 25 formulations were evaluated and those that passed the size screening and after showed the lowest interfacial tensions were then analyzed using the column load recovery and oil recovery by spontaneous imbibition tests.

The results of the study showed that for those selected conventional surfactants reformulated with the nano-sizer to generate the equivalent Nano-Surfactant versions, not only managed to drop the size of the micelles well below the 100 nm mark but also reduced the interfacial tension down to 10−4 mN/m to enable faster load recovery by up to 84% and the oil recovery by up to 227% per spontaneous imbibition in the amott cells - all tested with Wolfcamp Cuttings and Outcrop samples and crude oils from the Wolfcamp-A and B. As additional observation, the selected Nano-Surfactants showed general trends to lower emulsification of crude oil in the lab as well as in the field which is not always guaranteed with their conventional surfactant versions.

The chemical solutions implemented in the Permian using the formulated Nano-Surfactant versions, managed to increase the barrel of oil equivalent (BOE) in average perforated feet from 26 bbl/ft with the conventional surfactants to 34 bbl/ft with the Nano versions in the Upper Wolfcamp for the first 12 months of production with a marginal cost increase.
Performance of Inflow Control Devices (ICDs) in Horizontal Injection Wells with Injection Induced Fractures
Authors: Hu Jinchuan , Ou Yuhao , Zheng Shuang , Sharma Mukul , Clemens Torsten , Chiotoroiu Maria M.
Published: October 2023

Inflow Control Devices (ICDs) have been extensively used in injection wells to control the injection profile. The design of ICDs is usually based on the permeability and thickness of each injection zone. The primary objectives of this paper are to (a) study the influence of ICDs on the initiation and propagation of injection induced fractures (IIFs), (b) to demonstrate the importance of injection induced fractures on the design and placement of ICDs in horizontal injectors.

A fully coupled reservoir-fracture-wellbore simulator is applied to study the performance of injectors with ICDs. The simulator implicitly couples the performance of the ICDs with multi-phase flow in the reservoir, solid mechanics, thermal effects and allows for fracture propagation and particle plugging. The stress field in the reservoir accounts for thermo-poro-elastic effects during cold water injection. Fracture initiation and propagation induced by both internal and external filtration and thermal effects are simulated. The ICD pressure drop is implicitly solved in the fully coupled non-linear system of equations using a Newton-Raphson method. This allows us to predict fracture initiation and growth in different sections of the well over time. The impact of ICD placement and characteristics can be clearly evaluated by the model. It is shown that the growth of injection induced fractures plays a dominant role in the performance of the ICDs and controls the injection flow profile.

The flow distribution without ICDs can vary significantly with time due to injection induced fracture growth. Injector performance is evaluated for different ICD arrangements. The ICDs are shown to effectively control the flow distribution along the wellbore for better conformance control. If properly designed, ICDs can help to minimize the impact of potential "thief" fractured zones. While ICDs reduce injectivity by creating an additional pressure drop, the flow is much more evenly distributed, and this can help to slow down the injectivity decline, improve reservoir sweep and oil recovery. The results show that, in most cases, more ICDs and specific ICD arrangements can improve the injection profile to increase the recovery and decrease the risk of out zone fracture growth.

This paper presents a method to study the influence of ICDs and injection induced fractures on water injector performance using a fully coupled reservoir-fracture-wellbore model. The model, for the first time, presents results showing the dynamics of growth of multiple fractures in segments of the injector wellbore separated by ICDs and the impact they have on the flow distribution in the well. These results form the basis for the design and placement of ICDs in horizontal injectors.
Fiber Assisted Enhanced CO2 Foam Fracturing and Proppant Placement
Authors: Khan Abdul Muqtadir , BinZiad Abdullah , Alshammari Fahad O. , Glaznev Ivan
Published: October 2023

Low-pH fracturing fluid systems face a challenge to maintain rheological stability at elevated temperatures beyond 300°F. The objective is to have a reliable fluid system with high foam quality and viscosity demonstrating required proppant transport and retained permeability at the end of the treatment. To best balance the tradeoff, a solution that has been utilized for many treatments is to viscosify a novel biopolymer-based slurry gel fluid system with CO2. There are associated challenges with this strategy, though, in generating sufficient fracture width to place higher proppant concentrations. In this paper, we summarize a case study where enhancement of foam stability utilizing degradable fiber showed some improvement in proppant placement performance.

Degradable polymer fiber with novel polymer rearrangement was utilized to enhance the performance stability and used with the base fluid. Foam half-life was measured by varying fiber concentrations from 0 to 32 lbm/1000 galUS. Static and dynamic proppant transport was also studied by varying fiber concentrations from 0 to 22 lbm/1000 galUS. Proppant utilized for this testing was high-strength ceramic proppant. After the laboratory phase, fracturing treatment was implemented in two wells with CO2-assisted foam fracturing with (Well-B) and without the fibers (Well-A) to analyze the impact on proppant placement.

Three different fiber products made of different synthetic polymers were utilized in the initial phase to compare for proppant settling, and the high-temperature (HT) version was selected based on superior proppant suspension at high temperatures. For the next evaluation phase, the addition of HT fibers increased the foam half-life from 100 minutes to 200 minutes for 0 and 32 lbm/1000 galUS loadings, respectively. Similarly, the proppant settling time was increased from 59 minutes to 152 minutes for 0 and 15 lbm/1000 galUS loadings, respectively. Slot tests were conducted in a 3-mm slot to evaluate proppant transport in dynamic conditions and showed no sand banking effect with fibers. Tests were conducted with 0, 8, and 22 lbm/1000 galUS of fibers and show a clear impact of the fiber addition. During the field implementation, the HT fiber addition of 20 lbm/1000 galUS demonstrated 15% lower friction analyzed from treating pressure trends at the end of treatment. Also, no indications of near-wellbore bridging, or entry issues were observed in Well-B, similar to Well-A where CO2 foam was pumped without fibers.

The implementation of this approach can be impactful for CO2 foam treatments and can also be easily extended to liquid CO2 or supercritical CO2 fracturing, which provides the worst case environment for friction and proppant transport.
Significant Reduction of the Viscosity of Waxy Oils by Electrical Treatment
Authors: Wang Hao , Lu Yingda
Published: October 2023

Wax crystallization at low temperatures sharply increases the viscosity of waxy oils, posing difficulties to their pipeline transportation. Conventional methods of lowering the viscosity of waxy oils include adding chemicals or externally heating the pipeline, both of which are energy costly and carbon intensive. In light of the need for low-carbon and sustainable energy production, we present an environmentally benign concept that lowers the viscosity of waxy oils by electric fields generated from renewable sources.

The viscosity of model waxy oils (mineral oil + decane + paraffin wax) before and after electrical treatment was characterized by a rheometer equipped with an Electro-Rheology accessory. We monitored the oil's viscosity changes in three consecutive 10-minute stages: before, during, and after the application of DC electrical fields ranging from 0 to 3.5 kV/mm. The results show that the viscosity of waxy oils can be significantly reduced upon the application of electric fields and the highest viscosity reduction achieved is 82%. The magnitude of viscosity reduction strongly depends on the treatment temperature and the strength of the applied electric fields. Notably, the model oil systems used in this work contain no asphaltenes and resins, which challenges the widely agreed theories in the literature that the presence of charged colloidal particles like asphaltene and resin in waxy crude oils are the prerequisites for electrical treatment of waxy oils to be effective. The observed viscosity reduction is speculated to be caused by a combination of electrophoresis, Quincke rotation, and electrohydrodynamics. Overall, this technology of electrical treatment presents new opportunities to remediate wax-related flow assurance issues in a low-carbon and more sustainable manner.
Preventive Maintenance Schedule Automation in Oil and Gas Facilities Using Constraint Programming
Authors: Chandola Gaurav , Singh Sanchit , Kundu Manas , Jaysval Kishankumar , Onwusoh Mark U , Ukanah Joseph A
Published: October 2023

This paper presents details of an optimization tool which is developed to automate the week-wise preventive maintenance (PM) scheduling of equipment on oil and gas facilities for a 5-year scheduling horizon. The tool has been developed employing constraint programming (CP) paradigm and employs IBM ILOG CP Optimizer as the optimization engine. The tool takes the schedule auto generated by the computerized maintenance management systems (CMMS) as an input and efficiently load-levels the weekly-loads distribution by rescheduling maintenance activities from their scheduled dates while ensuring relevant business constraints are satisfied. The performance of the tool has been tested on certain maintenance service centers and the obtained results are in good agreement with the business requirements. The run time of the tool for generating the load-leveled schedule on the test cases is of the order of ∼10 mins per work-center. This tool results in considerable time savings resulting from the automation of the load leveling procedure. Additionally, the tool enables quick identification of problems with the input schedule which would lead to infeasibility and is easily adaptable across multiple facilities, thanks to the rich library of scheduling constraints in CP optimizer, helping test different planning scenarios.
Failure Analyses of Gas Lift Valves that Caused Improper Tubing-Annular Communication in Subsea Wells
Authors: Bastos S. X. , Oliveira G. H. , Sanomya T. , Ribeiro G. S.
Published: October 2023

This work presents the results of several failure analyses of gas lift valves retrieved from Petrobras subsea wells. These valves were unable to prevent the backflow from tubing to annulus, so compromising the well integrity. The purpose of these analyses was to unveil the root causes of the failure, which is essential information to prevent its recurrence.

When a tubing-annulus communication is detected and a damaged gas lift valve is identified as the cause of the problem, the valve is retrieved and transported to the workshop preserving as much as possible the conditions found when it came out of the well, allowing the inspection of solid deposits, elastomers and debris. At the workshop, the valve is opened and thoroughly examined, debris and solids are collected and, if relevant, chemically analyzed to lay down the root causes of the failure.

The results point to different causes for the failures: inorganic incrustations deposited in various parts of the equipment; abrasion caused by erosion and even pieces of foreign bodies, such as fabrics and wood, stuck in the valve. By associating the well operational history with the failure conditions, the causes and the chronology of events can be determined.

These investigations allow a more precise diagnosis of the gas lift valve failures, that tend to reduce the risk of recurrence of the problems and guide the correction of fragilities in current designs. They also can contribute to better planning and definitions on future well completions, resulting in increased reliability for this method of artificial lift.
Integrity Management of Offshore Process Piping and Equipment with Sand Production – Part I: The Pinhole Incident
Authors: Shirazi S. A. , Darihaki F. , Yamazaki Y. , Nakano Y. , Ushiguchi K. , Quang V. Lam , Le Ngoc L.
Published: October 2023

Sand production is becoming a growing issue for oil and gas operators around the globe. Operators are faced to increase production of oil and gas, which may cause or worthen sand production, while insuring integrity management of process piping and equipment. As a result of higher than expected sand production in a specific field, a pinhole failure was observed on a 12″ Schedule 160 elbow downstream of a Multiphase flow meter (MPFM) that contained a venturi section that caused a localized increase in flow velocities. State-of-the-art Computational Fluid Dynamics (CFD) based erosion prediction procedure was utilized to determine the root cause of failure and help operators with integrity management of the associated piping systems and equipment. Data used for verification of erosion model included wall thickness losses and sand production data in a separator downstream. Additionally, CFD simulations of erosion rates in 12″ elbows were used for evaluating simplified erosion models that are being used to determine Integrity Operating Window (IOW) of piping that are currently installed downstream of the MPFM. The results in the paper include a comparison of wall thickness measurements and erosion rates of the piping downstream of the MPFM with predicted erosion rates. The CFD predicted erosion pattern and wall thickness losses downstream of the MPFM were comparable with the observed erosion rates. The geometry of MPFM and downstream section was too complicated to model with simplified mechanistic models, but the results of CFD and the mechanistic models were more conservative for isolated elbows downstream where wall thickness data were available with ultrasonic thickness (UT) measurements. The results indicate that simplified mechanistic model of Shirazi, et al. (1995, 2016) was sufficient to support developing sand erosion IOW prediction tool and determining condition monitoring locations, provided that a practical process for wall thickness measurements at critical locations is in place for verifying the outcomes and fine tuning the models on regular and as needed basis.
First Industrial High-Power Laser Perforation Deployment
Authors: Batarseh Sameeh I. , Alerigi Damian P. San Roman , Marshall Scott , Graves Ramona
Published: October 2023

This paper presents the industry's first high-power laser field perforation and deployment—a successful high-power laser technology application. The innovative technology could perforate a well without affecting the substrate integrity and damage. The technology is safe, efficient, and cost-effective, providing a long-term alternative to shaped charge guns.

High-power laser technology has been tested and proven to effectively perforate in all rocks, regardless of strength and composition, including carbonate, shale, sandstones, and others. The success of the past two decades of intensive research has led to the development of the first high-power laser field system. The system's design is enclosed, providing safe and environmentally friendly operation; it consists of a laser energy generator, nitrogen tank, coiled tubing, and tool. The device's function is to control the size and shape of the beam that focuses on the targeted formation. The perforation process is done by utilizing the power of a laser to melt, spall, or vaporize the formation. The laser perforation tool can perforate through the casing, cementing into the formation.

The technology was deployed in a cased well. The well is logged pre- and post-laser perforation, and the coiled tubing is used to connect the fiber optics cable with the optical bottom hole assembly (oBHA). The tool can perform multiple perforations in a single trip, with the azimuthal orientation controlled by rotating the head of the device. Laser perforation creates a nondamaging controlled perforation tunnel penetrating casing, cement, and formation, and it is stress independent.
Seismic Reflectivity Inversion Using a Semi-Supervised Learning Approach
Authors: Rahman A. S. Abd , Elsheikh A. H. , Jaya M. S.
Published: October 2023

Seismic reflectivity inversion is a critical component in subsurface characterization, playing an indispensable role in resource exploration and reservoir studies (Tarantola, 1984). Conventional inversion methods have traditionally relied on optimization-based techniques, which often necessitate prior low-frequency models, and are not only susceptible to noise but also prone to introducing biases due to their dependence on initial assumptions.

In recent years, deep learning, using deep neural networks (DNNs), has emerged as a competitive approach for seismic inversion, capable of capturing complex relationships within data (Valentine & Trampert, 2012). However, supervised deep learning models are heavily dependent on the availability of labeled data, which is not always abundant or easily attainable (Alaudah & AlRegib, 2019). Furthermore, many existing models focus on predicting single points in reflectivity series, not adequately accounting for broader contexts within the seismic data (Wu et al., 2019).

In this study, we present a novel semi-supervised deep learning approach for seismic reflectivity inversion that leverages both labeled and unlabeled data to produce high quality reflectivity estimates. Our model employs a sequence-to-sequence (Sutskever et al., 2014) architecture, operating directly on raw seismic data, and is capable of capturing broader contexts, thus ensuring the continuity and complexity of the reflectivity series. Additionally, it minimizes the reliance on prior low-frequency models, enhancing the model's generalization capabilities. We present a comprehensive evaluation of the proposed method through a series of experiments on synthetic datasets, contrasting its performance against conventional seismic inversion and supervised DNN methods. Moreover, we discuss the key advantages, potential limitations, and avenues for future research in the application of semi-supervised deep learning in seismic inversion.