bluuebunny/crossref_metadata_2025 huggingface dataset:
Perf Guns, They’re Not Just for Holes Anymore! Perf Cluster Tracer Injection
Authors: Squires Christopher , Leonard Brad , Geerts Shaun , Clay Matthew
Published: September 2022

Oilfield water and oil tracers have historically been pumped into the fracturing fluid during well stimulation. This paper will introduce an alternative method of injecting oilfield tracers that utilizes perforating guns with energetic propellant to force the tracer into a perforation cluster prior to fracturing operations. Direct tracer injection from perforating guns offers several advantages to operators that are interested in oilfield tracer diagnostics, they include:

Monitoring a wells oil or water returns down to an individual cluster level of resolution. Energetic propellent assisted perforation cluster breakdown. Direct tracer injection into clusters for wells that are: Perforated but not hydraulically fractured. Bullhead refracturing treatments with long open intervals of newly fired perforations. Not sufficiently isolated between stages from poor cementing or leaking plugs. Not isolated or experimentally isolated between stages.

Oilfield tracers in solid form were first injected into perforation clusters with energetic propellants on two Marcellus Shale wells. The primary purpose of this experiment was to determine if Perforation Gun Tracing (PGT) could be used to provide flow-assurance diagnostic information to the well operator. Additionally, standard liquid water tracers were also injected into the flowstream during the corresponding fracture treatment stages and used as a control for the PGT. Both tracer injection methods indicated that the toe side of the wellbore was contributing to the fluid returns profile and also showed similar trends in tracer response over time. This experiment showed that PGT could provide valuable diagnostic information to well operators.

Several additional field trials that exploit the unique benefits of PGT were completed after the success of the initial experiment and are included in the case studies section of the paper. In each case, PGT was able to provide the intended diagnostic which included flow-assurance, flow-profiling, fracture driven interactions and/or refracturing effectiveness.

In refracturing, PGT has tremendous benefits because the energetic propellent can help the new perforations breakdown and compete with the existing broken down and eroded perforations. Additionally, unique tracers are injected at several known cluster depths throughout the lateral. Any returns of the unique tracers in the flowback water will correspond to fracturing fluid that has contacted the depth of that specific traced cluster. This provides an operator valuable diagnostic information to determine how deep their refracture treatment was able to reach into the lateral. PGT also delivers information on the returns of an individual cluster, without post-frac well intervention or permanent hardware installation.
Deep-Learning-Based Direct Forecast Approach for Fractured Shale Gas Reservoir Under Geological and Hydraulic Fracture Parameter Uncertainty
Authors: Xiao Cong , Zhang Shicheng , Ma Xinfang , Zhou Tong
Published: September 2022

Accurate ultimate recovery prediction and uncertainty quantification are of significance during the process of unconventional shale resources development field development plan formulation. The uncertainties related to characterization of geological parameters and especially hydraulic/natural fracture system are not readily quantified through conventional model-based history matching procedure in practical applications. Data-space inversion (DSI) is a recently proposed data-space analysis and rapid forecast approach that easily samples the posterior predictions based on an ensemble of prior predictions and historical measurements. This paper presents a novel methodology based on a hybridization of DSI and a vector-to-vector residual neural network, referred to as DSI-DL, for well production forecast in unconventional shale reservoirs. A data-augmentation strategy that has been exploited in the literature is employed to generate a large number of training samples from a relatively small ensemble of shale reservoir model simulations. The DSI-DL method treats the shale gas production in our expected future time as target variables, which are directly predicted from pre-trained deep-learning model given historical data. This method enables us completely avoid the time-consuming history matching process where the characterization and inversion of hydraulic/natural fracture topology are highly complicated. We demonstrate the performances of this new approach on a synthetic vertically fractured well and a multi-well production scheme in naturally fractured shale formation. Some comparison with conventional DSI procedure and model-based history matching have shown that DSI-DL method achieves relatively robust results in estimating P10-P50-P90 values of shale gas time-series production against to data noise and prior ensemble size. DSI-DL algorithm will greatly contribute to the real-time prediction and optimization of shale gas well production rapidly given the streaming online observation data and have a wide range of practical application prospects, while a high computational efficiency remains. The proposed DSI-DL approach definitely will be useful for petroleum engineers to assess the value of information and manage the uncertainty of unconventional resources development.
Detectable Radius of Investigation for One Flow Period with Bourdet Derivative
Authors: Jiang Lei , Chen Li , Yu Hua , Kristensen Morten , Gisolf Adriaan , Dumont Hadrien
Published: September 2022

A new definition of the radius of investigation (ROI) is proposed to overcome the ambiguity present in the results from conventional ROI quantification methods.

The term ROI is commonly used to quantify the minimum reservoir size or the distance to a potential boundary evaluated through pressure transient testing. However, the various methods that exist in the literature to quantify ROI provide different answers stemming from varying assumptions and thus often lead to confusion in terms of the appropriate definition to choose. Although the ROI method developed by Van Poolen is well recognized in the industry, there is a debate about its general applicability because it is limited to a constant-rate flow period and is insensitive to flowrate and flow sequence, to gauge resolution or measurement noise level. This contrasts with operational experience, where a higher flowrate, higher gauge precision, and a lower level of measurement noise generates higher quality pressure transient testing data from which reservoir boundaries, or other features, can be identified farther away from the wellbore. In other words, higher flowrates, better gauges, and lower noise levels can lead to larger achievable ROI.

We propose a new definition of ROI, that is the detectable ROI for each drawdown or build-up flow period and is derived from the actual pressure derivative response and not from a generic model assumption. By defining a derivative noise envelope, the new method clearly identifies the time when the derivative deviates from an unbounded model due to the presence of a boundary and thus provides an estimate of the detectable ROI for the analyzed period.

This method overcomes the limitations of most conventional methods and provides ROI predictions that depend on flowrate and gauge noise while maintaining a consistent result with current pressure transient interpretation.
Lessons Learned in a Decade of Automated Reservoir and Production Engineering Surveillance
Authors: Fair Chris , Flores Ricardo
Published: September 2022

Introducing new technology in the oil patch is not for the faint of heart. Introducing automation, which some perceive as threatening their jobs, as opposed to making their jobs easier and their decision process more efficient, requires some form of irrationality. With this in mind, the authors would like to take the readers through their journey of the last ten years, with the hope that others can learn from their experience.

Without making any claims about the efficacy of the technology (Fair, 2014) to solve every problem an operator has, and without badmouthing any potential competition (Lesson 1: Never do this! It makes YOU look bad!), the authors introduced the technology via the ‘drug dealer’ method: The first time is free…When people come back for more, start charging. The technology was introduced and trialed at most majors and many of the larger independent companies, with a surprising amount of early adoption. There was then a significant bifurcation in the way the majors and the independents behaved.

Amongst the independent operators or majors with operating units that acted like independents, acceptance of the technology in the U.S. Gulf of Mexico and North Sea was very binary. Either it was accepted as plausible and at least tried-out, or it was declared impossible and outright rejected.

Amongst the majors and the independents that act like majors, the entry path to a trial was byzantine. A couple of majors never accepted free trials. Amongst the others that did go to a trial, once the trial was completed, it never led to implementation…rather, it led to years-long internal R&d (that’s right…Big R, small d) efforts, usually resulting in nothing. This inevitably led the holders of the purse strings to declare that since their internal experts couldn’t duplicate or even understand the technology, it was therefore impossible and/or does not work.

The reason the engineers and managers at the independents adopted the technology was that they were ‘closer to the coal face’. It didn’t matter if they understood all of the details of the technology. What mattered was simple: Can using this technology make the company more money (or save it more money)? Quite frankly, the technology implementation was more successful the less the company management cared about understanding the minutia.

This paper presents a firsthand account of how technology is absorbed or rejected by different company types in the oil & gas industry and seeks to explain the reasoning behind their decision-making. It also provides some guidance to others who wish to bring new tech to the oil patch.

Note: This will not be a formal technical paper. This will be more akin to an editorial/advice column, presented in a way that hopefully helps the reader use their time more efficiently and promote their ideas more successfully. As such, a good portion of the article will not be written in third person.
Analysis of Tidal Behavior of a Horizontal Well to Determine Reservoir Properties
Authors: Lu Xunfeng , Sato Kozo , Horne Roland
Published: September 2022

Tidal analysis requires only continuous pressure monitoring data and therefore is a cost-effective technique for estimating reservoir properties. Previous tidal analysis work focused on vertical wells. This study developed and solved tidal response models for a horizontal well considering skin effect and wellbore storage in three classical reservoir types: confined reservoir, semiconfined reservoir, and reservoir with mixed boundaries.

Green's function, source functions, Laplace transform, and Duhamel's principle were used to solve the models and obtain analytical solutions in Laplace space. Then, Laplace transform numerical inversion was utilized to invert the Laplace space solutions to time-domain solutions. Variable condition analysis was conducted to analyze the effects of different parameters (wellbore storage, skin effect, well length, well direction - horizontal or vertical, and vertical leakage) on tidal behavior:

For confined reservoirs, the influence of skin effect and wellbore storage (under the condition of positive skin effect) both tend to decrease the tidal amplitude ratio and increase the tidal phase lag. Longer wells lead to a smaller tidal amplitude ratio and lead to a larger tidal phase lag for small wellbore storage, and smaller tidal phase lag for large wellbore storage.

For reservoirs with mixed boundaries, the effect of wellbore storage depends on the value and sign of skin factor. A horizontal well with larger skin effect will have larger tidal phase lag and tidal amplitude attenuation.

For a semiconfined reservoir, the tidal amplitude ratio first increases with increasing vertical leakage but then decreases when there is a large vertical leakage. Vertical leakage tends to decrease the tidal phase lag or increase the tidal phase advance.
Successful CO2-Foam Field Implementation for Improving Oil Sweep Efficiency in EVGSAU Field at Permian Basin: Expansion Phase
Authors: Hassanzadeh Armin , Katiyar Amit , Kalaei Hosein , Pecore Doug , Schofield Ephraim , Nguyen Quoc , Gilchrist Corey
Published: September 2022

A successful CO2-foam technology has operated at the East Vacuum Grayburg San Andres Unit (EVGSAU) since Jan 2018 by ConocoPhillips in cooperation with Dow. In early 2020, scope of the technology was expanded from one pattern to three patterns. The expansion phase was implemented to evaluate scalability of this technology to patterns with diverse conformance issues and productivity inefficiencies. Severe vertical and areal conformance issues were initially identified in these patterns, resulting in early gas breakthroughs and poor oil sweep efficiencies. Due to the outstanding performance of the first phase, the same surfactant with high foaming tendencies, high gas solubility, and low adsorption characteristics was implemented in the new patterns.

In contrast to the first foam pattern, gas injectivity was reduced by 20 to 50% after only 2 foam cycles in the new patterns. Based on injection profile logs (IPL), no out-of-zone injection was identified before the surfactant injection for the two new patterns, which can be the reason for such rapid injectivity responses. Similar to the first pattern, deep conformance corrections were confirmed as gas was redirected from highly connected producers to other producers within the new patterns. A lower surfactant dosage was applied to one of the new patterns to optimize chemical consumption, while sustaining the performance. The surfactant concentration was also reduced in the first pattern to study the effect of a lower dosage on a known performing pattern. During the foam implementation, the gas to water ratio (GWR) at the pattern injectors was increased to maintain the patterns at the baseline fluid throughput. This adjustment resulted in more than a 50% reduction in water consumption and a 17% improvement in gas utilization. Overall, a sustainable increase in oil production rate (30 to 40% over the baseline for the last two years) was achieved in the three foam patterns as a result of the foam implementation.

This three-pattern CO2-foam field result is an outstanding example of how proper implementation of a novel surfactant in a conventional reservoir with mild-to-severe deep conformance issues can improve oil sweep efficiency. The application of this foam technology has demonstrated the extension of the life of a mature asset like EVGSAU by arresting the historical decline in the oil production rate. Reduction in energy and water consumption per barrel of oil produced, and further CO2 sequestration are other benefits of this technology.
Risk Mitigation Measures Implemented by Use of Expandable Liner to Prevent Alpha-beta Gravel Pack Failure When Unstable Shale Formation is Exposed
Authors: Ioan Tiberiu , Essmat Nooruldeen Zeyad , Moroni Gianluigi , Sallis Jonathan Neil
Published: September 2022

Current oil and gas volatile market environment and the increase focus towards sustainability, it is essential to develop more economically and ecofriendly technologies in oil and gas industry environment. Maintain well integrity is mandatory towards developing oilfields to contain the reservoir fluids within the wellbore, however it becomes more critical in developing new underground gas storage reservoir in Italy. During construction phase of gas production and storage wells, one goal, besides hydraulic isolation of the production casing with cement, is the sand production containment during production cycle of the field. Sand production, even in small quantities, will eventually erode downhole and surface equipment leading to potential catastrophic scenarios of uncontrol reservoir fluid reaching surface. These can have significant health, environmental, and economic impact. Additionally, the impending need for well intervention, along with high re-entry costs, will further weaken revenue margins.

In high permeability reservoirs required for underground gas storage projects, the injection and production cycles can lead to stresses applied in nearby wellbore formation which will destabilize the sandstone grains leading to sand production. To mitigate the sand production into the wellbore, a gravel pack operation will support the wellbore, consolidating the space behind the production screens.

In this field, a high-risk failure was identified for traditional alpha-beta gravel pack methodology. This could lead to expensive recovery operations for the client and service provider to restore the well and re-perform the gravel pack. To tap different part of the reservoir, one well in particular had to be sidetracked from 9-5/8in casing resulting in a long clay interval being exposed susceptible of instability. It was required to isolate this interval to avoid disturbing the clay interval during gravel pack operations, however, to accommodate the completion, the optimum solution was to use expandable liner. Using this zonal isolation technique to regain well integrity, along with redesign of gravel pack carrier fluid technology led to a successful job securing client position as a reliable field operator. The field operator was committed for high level of safety during operations, starting from design phase through the execution, to achieve long-term well integrity and performance.
Reservoir Fluid Geodynamics using Logging-While-Drilling Downhole Fluid Analysis: A North Sea Case Study
Authors: Betancourt Soraya S. , di Primio Rolando , Blanco Yon , Stirø Øyvind , Lopes Velerian S. , El-Khoury Jules , Dykes Thomas A. , Mullins Oliver C.
Published: September 2022

We present a case study of the application of Fluid Mapping While Drilling (FMWD) to acquired logging-while-drilling downhole fluid analysis (FMWD-DFA) in the development stage of a North Sea reservoir. An extensive Wireline DFA (WL-DFA) dataset and Reservoir Fluid Geodynamics (RFG) study helped characterize fluid variations in the exploration and appraisal stages of this field revealing a complex reservoir charge history that results in fluid variations throughout the field and furthermore revealing connections between reservoir quality/productivity and in-situ fluid properties. In the development stage, knowledge acquired in the previous field phases guided well placement decisions and FMWD-DFA was used actively in well construction to validate and enhance the fluid model in this field.

FMWD pressure and DFA measurements were acquired in five development wells in the field: three horizontals and two high-angle pilots. DFA measurements provide fluid composition and optical density, which correlates directly with the asphaltene content of the oil. Asphaltene gradients are modeled to assess thermodynamic equilibrium conditions and investigate lateral and vertical connectivity. DFA and other data streams integrated by the RFG analysis provided the base model: a relatively recent secondary migration of light hydrocarbon into the reservoir that resulted in different realizations of the mixing process depending on distance from the charge plane and rate of mixing. Well trajectories were designed to target sweet spots based on appraisal data; however, some level of uncertainty remains when entering the development stage. FMWD-DFA was used to understand fluid property variations throughout the field that may be associated to geological factors or resulting from fluid mixing processes that may yield localized asphaltene instability. FMWD pressure and mobility measurements complement this model and enable an assessment of current levels of pressure depletion from production in a neighboring field in hydraulic communication through a shared aquifer.

This field example shows integration of DFA technology from different acquisition platforms at different stages of the life of the field. It illustrates how this technology is used to improve the understanding of the complex fluid variations in this field and make development decisions such as optimizing well design by ensuring placement within reservoir sweet spots.
Finally, a Low Cost and Autonomous Method of Generating Corrected Mechanical Specific Energy for Improved Decision Making, Drilling Performance, and Rock Property Characterization
Authors: Kilb Justin , Brame Brandon , Anderson Kaleb
Published: September 2022

Despite decades of research focused on Mechanical Specific Energy (MSE), drilling operations still fail to operationalize MSE as the primary drilling-based performance indicator. This is partly because the availability of MSE in Electronic Drilling Recorders is usually calculated with surface measurement, which fails to isolate energy spent solely at the bit. Removing energy spent along the drill string is important because it allows operators to establish an expectation of the total energy necessary to overcome the confined compressive strength (CCS) of the rock. Once this baseline is established, an increase in MSE versus the CCS can be recognized as wasted energy and therefore, inefficient drilling.

Methods to correct MSE exist but are time-consuming when done manually and may require specialized software. As a result, scaling corrected MSE can be challenging. To address these issues, this paper presents an accessible MSE at Scale workflow that provides a fully automated, physics-based drilling efficiency and design platform for full-fleet implementation. The methods included explore a wide breadth of optimization techniques that can be utilized by operational personnel and autonomous drilling rigs, thus also supporting the future of physics-based intelligent drilling systems.

After discussing the data pipelines and methods of calculation, drilling results from over half a million lateral feet are presented. This analysis is separated into two workflows: Big Data MSE for design optimization and rock characterization, and real-time MSE streaming for operational guidance. A new MSE versus rate of penetration process is introduced, which will allow operators to determine a bit’s maximum formation specific performance (MFP), in one run, regardless of operating conditions. Additionally, generating high-resolution corrected MSE, per foot, provides an alternative and in-situ solution for CCS that does not require petrophysical software or log data. Lastly, a new Cumulative MSE process is introduced to offer a change of perspective in the way we understand and measure bottom hole assembly (BHA) durability.

The latter half of this paper discusses derivations of the MSE equation to offer power-based metrics that are more intuitive than MSE and therefore, may be easier to adopt in field-operations. This is because BHA power, which is a function of rotational energy, presents a consistent and predictable diminishing of ROP returns. This relationship appears to behave similarly to the founder point, yet it is predictably adaptive to drilling parameters beyond solely weight on bit. Finally, this paper discusses a machine learning technique to detect real-time drilling performance that can potentially indicate failing or weakening BHA equipment.
Remediation of On-Bottom Stability (OBS) Issue During Offshore Installation of Light Weight Structure (LWS) at Malaysia Water
Authors: Helmi Bin Ngadiman , Szaini Zainal Abidin , Faizal Shahudin , Nur Dalila Alias
Published: September 2022

This technical paper presents the strategy adopted by COMPANY for Remediation of On-Bottom Stability (OBS) Issue during offshore installation of Light Weight Structure (LWS) at Malaysia Water at water depth of 54m. The knowledge sharing is based on the successful remediation work in managing the OBS issue where the substructure experience excessive tilting.

The LWS is designed with minimal mudmat. In addition to that, the subsea pin pile is designed to improve substructure on bottom stability issue during substructure installation. However, during actual offshore installation of substructure, the behavior of the substructure upon setting down on seabed was not as per the intended design where the substructure tilting is observed after substructure landing onto pin pile.

As mitigation, the following approaches have been implemented to safeguard the substructure from toppling:

Safeguard of Substructure Risk assessment and immediate action have been taken by temporary safe holding the substructure by connecting holdback lines between substructure and installation barge bollards. Revisit OBS engineering study and analysis Revisit on bottom stability engineering study and lifting analysis considering changes to procedure/method by increasing the initial pile length (82m) to allow for early self-penetration. Revisit pile installation and sequence The piles have been re-fabricated onboard installation barge by utilizing the chaser rack at DB portside. The chaser rack was fabricated at site with available surplus material onboard DB. Once the revised pile fabrication completed, the piles were installed into the substructure leg for self-penetration. Result of Remediation Work After successfully securing the substructure by installing the 82m pile length at one (1) leg of substructure, it has resulted that the substructure OBS has been improved to allow the COMPANY to proceed with original installation plan sequence as per installation procedure. Ultimately, COMPANY has managed to avoid catastrophic event.

Despite all the challenges, the installation of LWS were completed successfully, no damage to property and most importantly with Zero Lost Time Injury (LTI).
Geological Storage of Carbon Dioxide and Hydrogen in Jordanian Shale Formations
Authors: Samara Hanin , Von Ostrowski Tatjana , Jaeger Philip
Published: September 2022

The success of large-scale geological storage of gases highly depends on the interfacial properties and gas adsorption capacity of the formation in question. To infer a clear understanding of the behavior of hydrogen (H2) and carbon dioxide (CO2) at conditions relevant to their storage, a systematic study relating pressure to the gas adsorption capacity of Jordanian shale formations is conducted. Additionally, the pendant drop method and the Axisymmetric Drop Shape Analysis technique are used to measure and evaluate brine-gas interfacial tension (IFT) as a function of pressure and salinity at 333 K. The wettability of Jordanian shale is also measured using the sessile drop method at different gas pressures and varying salinities. The results show that the adsorption capacity of shale is positively correlated with pressure. CO2 adsorption capacity is found to be orders of magnitude higher than that of H2 under similar conditions. Conversely, the measured CO2 diffusivity is an order of magnitude lower than the diffusivity of H2. The results also show that IFT increases with increasing salinity in both brine-gas systems and decreases with pressure, nevertheless, the reduction in IFT is much more evident in brine-CO2 systems. Additionally, the initially water-wet shale becomes highly CO2-wet at elevated pressures, while for H2, the shale remains water wet under all experimental conditions.
Apply Reduced-Physics Modeling to Accelerate Depletion Planning Optimization Under Subsurface Uncertainty
Authors: Sanaei Alireza , He Shuai , Pope Joshua , Verma Santosh , Mifflin Rick , El-Bakry Amr
Published: September 2022

Robust decision-making regarding reservoir management using model-based strategies requires a large number of evaluations which can be enormously time-consuming if incorporating the full-field simulation. This challenge becomes more acute when dealing with subsurface uncertainty represented by multiple geologic scenarios. Various reduced-physics and reduced-order models such as streamlines and upscaling are commonly applied to accelerate the optimization process by reducing the computational burden of each evaluation. In this paper we propose an innovative integrated workflow that applies Flow Diagnostics, a reduced-physics modelling tool, to accomplish this acceleration and the mesh-adaptive direct search (NOMAD) algorithm to efficiently optimize well location.

Flow Diagnostics (FD) is a reduced-physics approach that characterizes key flow behaviors and reservoir heterogeneity by combining a single-phase pressure solution with a time-of-flight estimator based on steady-state flux. The time-of-flight values for each grid cell can subsequently be combined with initial reservoir conditions to estimate saturation-weighted 3-phase production using 1D Buckley-Leverett fractional flow relationships. Our testing of this technique on a 2-phase, water flooding asset showed that, while it does not accurately predict exact volumes, there is a strong rank-order correlation with the full numerical simulator. Thus, this technique is an efficient one to assist in the decision-making and optimization process.

To demonstrate this workflow, we applied this strategy to a synthetic base model of a deep water reservoir. Synthetic uncertainty was added to the base case to generate multiple subsurface scenarios. Representative P10, P50 and P90 cases were selected to represent low-, middle-, and high-side cases based on cumulative distribution function (CDF) of NPV. Different well placement optimization studies using high fidelity models and reduced order models were then performed on these cases (optimization of each single scenario on its own and optimization across all representative scenarios simultaneously) to compare solutions and effectiveness. Results indicated that, when the optimized well plans were run on the simulator, optimization under uncertainty provided a solution more robust across the uncertainty space. The results of the full study successfully demonstrate the efficacy of our workflow.
Effect of Supercritical CO2 on the Poroelastic Characteristics of Poorly Cemented Sandstone Reservoirs During Depletion and Injection
Authors: Hashemi Sam S , Kovscek Anthony R , Zoback Mark D
Published: September 2022

While there is continuing interest in geologic CO2 storage, experimental studies on poroelastic characteristics of reservoir rocks during depletion and subsequent CO2 injection are scarce. Rock stiffness, confining stress, and pore pressure control the poroelastic response of saturated rocks. Also, the stress and pore pressure evolution during injection is a key parameter to understanding operations thresholds for CO2 storage projects. As depleted fields in the Gulf of Mexico have been identified as strong candidates for CO2 storage projects, it is important to understand if the poroelastic characteristics from such fields have been altered due to depletion. Among rock properties, Young’s modulus (E), bulk modulus (Kb) and Biot coefficient (α) are of particular importance.

In this study, the poroelastic deformation of a core from the West Delta field in the Gulf of Mexico is characterized experimentally and the impacts of supercritical CO2 (scCO2) on the specimen are investigated. The experimental program simulated reservoir stress changes due to production-induced depletion and scCO2 injection through cycling both the confining pressure (Cp) and pore pressure (Pp). We measured the deviatoric stress, volumetric strain, derived the corresponding Young’s (E), bulk moduli (Kb) and Biot coefficient (α). The results show that the effect of scCO2 on E is more significant at greater confining pressures during the injection phase than depletion at a constant simple effective stress. Interaction of scCO2 with clay minerals caused rock frame dehydration and led to an increase in E. The bulk modulus increased with increasing the confining pressure at a given Pp and decreased with Pp at a certain Cp. α rose with Pp during both depletion and injection phases. Interaction with scCO2 limited the variation of α and the effect of Pp and Cp on α decreased in significance during the depletion phase. Longer interaction time with scCO2 increased α from 10-25% at different Pp values compared to argon during the injection stage. However, the influence of effective stress in reducing the α weakened.
Developing a Fit-For-Basin Novel Solution with the First Application of iCore Behind Cased Borehole in a Complex Heterogeneous Miocene Carbonate Reservoir: Bakr Oil Field, Central Province of Gulf of Suez
Authors: Salim Sadek , Sayed Mayada , Abdo Ibrahim , Abdel Hakim Emad , Farouk Mohamed , Hegazy Amr , El Araby Abdelmoniem , Ghanim Mohamed , Saleh Khaled , ElZahaby Omar , ElNahrawi Mariam , ElKaragi Alaa
Published: September 2022

Gulf of Suez basin is one of the most complex areas of exploration that requires a fit-for-basin solution to reveal the true potential of the carbonate reservoirs. The multi-domain integration of the interpreted lithology from high-resolution imaging tools recorded in the open hole section with electrofacies integrated with NMR and cased hole elemental spectroscopy data provides the 1st time application to derive synthetic core with high-resolution facies in the drilled wells with complex heterogeneity challenges. 3D seismic attributes, stratigraphical and structural analysis, revealed a potential three-way dip closure with an expected high-quality carbonate reservoir. An automated processing workflow converts gamma-ray yields from the energy spectrum measured behind casing into the dry weight and mineral fractions. The computed mineralogical outputs are then described based on a standardized ternary diagram approach to generate dry-weight mineralogy-based lithofacies. The synthetic high-resolution lithofacies are integrated with MDT, NMR, and spectroscopy to capture mobility, type of fluid, and saturation associated with lithofacies changes which is integrated with well integrity analysis to plan, design, and execute of innovative technique for carbonate stimulation.

This paper demonstrates reviving exploration activity in one of the brownfields and the first application for borehole imaging integrated with cased hole spectroscopy on the recent discovery well to select perforation. Once a robust lithofacies classification is obtained, this is used for detailed stratigraphic analysis, well to well correlation, cross-sections, mapping or refined static reservoir modeling, and perforation zones selection which represents the first success story for this innovative technique. This multi-domain integration helped to design a customized acidizing technique to reveal the true reservoir potential that had a 3 fold increase in productivity index compared to offset fields in the same basin.

The workflow can be applied to multiple cases as a cost-effective solution in multiple scenarios and different formation types especially if there is no core available in old wells. Furthermore, the innovative acidizing technique can effectively stimulate any carbonate reservoir.
Evaluation of Image-Matching Analysis to Compute Downhole Drilling Distance for Directional Drilling Automation
Authors: Mansour Ahmed , Zerpa Luis , Sampaio Jorge
Published: September 2022

Drilling technology has been rapidly evolving over the past few decades, and currently, the main focus has been on enabling drilling automation. Multiple components on a drilling rig have been automated to make drilling operations safer, more efficient, and less costly. The invention of new directional drilling tools, such as Rotary Steerable Systems (RSS), has allowed directional wells to be drilled in less time and have decreased torque and drag. Directional drilling tools, in general, use inclination, azimuth, and depth measurements to locate the bit. As a result, the directional driller can orient the bit towards the desired location. While azimuth and inclination can be measured downhole, depth measurements are obtained using the pipe tally installed on the surface. As a result, it is difficult to automate current directional drilling tools because they still depend on surface measurements, manual input, and human guidance.

A continuous downhole measurement system that uses inclination, azimuth, and measured depth to determine the drilling bit's location would facilitate directional drilling automation. A downhole computer would compute all calculations in the bottomhole, allowing the bit to follow a preprogrammed trajectory rather than depending on surface instructions. Minimizing surface dependence allows smoother well paths, thus decreasing torque, drag, drilling time, and costs even further. Therefore, this paper introduces a technique that computes the drilling distance using multiple imaging sensors spaced at known distances. The sensors capture images of the same formation location at different but synchronized times. The method includes an image-matching algorithm that identifies each image's fingerprint and registers similar images according to those fingerprints. It then uses the timestamps of the matched images and the distance between the sensors to compute the local average rate of penetration and the distance traveled. Here, we explain the mechanism of the image-matching analysis and introduce the concept through experiments made on sceneries that imitate the wellbore wall. Additionally, we analyze the effect of controllable variables on the accuracy of the distance calculation.
An Optimum Well Control Using Reinforcement Learning and Policy Transfer; Application to Production Optimization and Slugging Minimization
Authors: Poort Jonah , Van der Waa Jasper , Mannucci Tommaso , Shoeibi Omrani Pejman
Published: September 2022

Production optimization of oil, gas and geothermal wells suffering from unstable multiphase flow phenomena such as slugging is a challenging task due to their complexity and unpredictable dynamics. In this work, reinforcement learning which is a novel machine learning based control method was applied to find optimum well control strategies to maximize cumulative production while minimizing the negative impact of slugging on the system integrity, allowing for economical, safe, and reliable operation of wells and flowlines. Actor-critic reinforcement learning agents were trained to find the optimal settings for production valve opening and gas lift pressure in order to minimize slugging and maximize oil production. These agents were trained on a data-driven proxy models of two oil wells with different responses to the control actions. Use of such proxy models allowed for faster modelling of the environment while still accurately representing the system’s physical relations. In addition, to further increase the speed of optimization convergence, a policy transfer schem was developed in which a pre-trained agent on a different well was applied and finetuned on a new well. The reinforcement learning agents successfully managed to learn control strategies that improved oil production by up to 17% and reduced slugging effects by 6% when compared to baseline control settings. In addition, using policy transfer, agents converged up to 63% faster than when trained from a random initialization.
Best-In-Class Water Control Through the Application of Autonomous Inflow Control Valves in Villano Field, Ecuador: A Case Study
Authors: Atahualpa Gustavo , Astudillo Ricardo , Chango Mario , Borquez Carlos , Rauzi Roberto , Uzcategui Alberto A. , Fipke Steven , Molina Juan Luis , Mohd Ismail Ismarullizam
Published: September 2022

Water control in mature heavy-oil reservoirs is a well-known challenge in the Oil & Gas industry. Due to the mobility ratio, water tends to flow much easier compared to oil, leading to premature water breakthrough which pushes water cut values to over 95% or more within weeks of oil production. High volumes of water production negatively impact operations due to excessive electricity consumption (lifting and re-injection), overuse of water handling/treatment facilities and its associated impact to the environment. In some fields, high water-cut can limit the oil production if the water handling capacity is exceeded, driving operators to shut-in wells and lose recoverable oil.

Villano is a mature heavy-oil field located in a tropical rainforest area in the Pastaza province, east Ecuador (17–19 °API and 25 cP). The field has been mainly developed with horizontal wells, where several water-control completion strategies have been trialed (ICD/AICD) due to the presence of an infinite-acting, strong aquifer drive. Although some positive results had been observed in the field, none of these technologies have been able to provide effective water control in the sections with water breakthrough.

After a technical evaluation, the AICD-Valve technology was chosen, and the first installation was planned for mid-2021. Due to its ability to autonomously restrict water flow based on the fluid properties (viscosity and density), simulation results showed short- and long-term benefits in terms of oil recovery and water control for the field.

The AICD-Valve technology has shown superior water control compared to other technologies used in Villano field. The well began its production with 4% water cut (compared to >50% with adjacent A/ICD completions) and approximately double the initial oil rate compared to modelling. The well eventually reached 80% water cut and stabilized at 80%–85%. Production rates have been very stable while the flowing bottomhole pressure has been dropping gradually, signaling that the AICD-Valves are autonomously choking the water zones while allowing production from oil zones. Water volumes produced from the AICD-Valve well are less than 1/3 of the neighboring A/ICD wells.
Relevance of Petroleum Engineering Under the Present Uncertainties
Authors: Farouq Ali S. M. , Soliman Mohamed Y.
Published: September 2022

Petroleum engineering will continue to have relevance and renewed importance in the emerging scenarios of Greenhouse Gas (GHG) emissions, and the forecasts of climate change, which are replete with uncertainties. The changing role of petroleum industry and academia in this framework over the next 100 years is outlined. The hurdles in reaching Net Zero – fossil fuel use with complete carbon capture and storage, and the use of renewables – are illustrated through a spreadsheet. Development of renewables is costly and has an environmental footprint 10 times that of oil and gas for the same amount of energy. Carbon capture and subsurface storage is a better option, and petroleum engineers are best suited to address that. They are also well positioned to develop energy using injection-production wells, and create storage space. Petroleum engineering, with its unique blend of skills and technologies is unmatched and needed for a long time.
Well Integrity in the Production Phase - Application of a New Quantitative Operational Risk Model
Authors: Oliveira Luiz Fernando , Domingues Joaquim , Colombo Danilo
Published: September 2022

Almost all O&G companies have a well integrity management system based on a well failure model. Until now, they are mostly based on qualitative risk models with only very few claiming to use quantitative risk methods. The objective of this paper is to present a production well integrity managementsystem based on a different type of quantitative risk model. Traditional risk assessment methods were developed to be used in design stage. Therefore, they are not really adequate to manage operational risks during the production phase because they cannot take into account the operational history and the true current asset conditions during operation. Unlike such models, our quantitative risk/reliability model has been developed to be specifically used during the operational phase of a well. Therefore, it can accurately calculate the risk of an uncontrolled leak today and provide good estimates for the future evolution of this risk.This quantitative model has been served as the basis for the development of a web-based computational system which is now implemented in Petrobras and is an important part of the well integrity management system of that company. A descriptionis presented in this paper together with a simplified application to a subsea well.
Maintain Long-Term Production Rates by Unique Environment Friendly Asphaltene Solvent
Authors: Omer Mohammed , Busteed John E. , Fragachan Francisco E.
Published: September 2022

Heavy oil production often results in the deposition of organic solids, like waxes or asphaltene. These asphaltene deposits pose a serious problem to the operator, negatively affecting the productivity of the reservoir, by reducing the permeability and altering wettability. Its deposition in production and tubing facilities can cause operational and economic issues. Various chemical and mechanical methods used for treating deposition are partially effective. Traditionally xylene has been used to remove these organic deposits, however, because of its low flash point (~80 °F) it poses a great risk of ignition. In addition, xylene does not change the wettability of the rock surface, resulting in short-lived effectiveness.

This paper outlines the development of an optimized environmentally friendly Asphaltene Solvent. Suitable for surface and bottom hole conditions. The paper discusses the production results and flow assurance observed from long-term production results from field trials performed in the Middle East. The optimized asphaltene solvent was designed and evaluated by dissolution, wettability and stability tests, and its results were benchmarked against actual xylene treatments, demonstrating and excellent flow assurance beyond standard xylene systems.

The laboratory testing demonstrated that the system was capable of dissolving Asphaltenes and Paraffins up to 99% -after 4 hours in a water bath at 194 °F (90 °C)- and leaving the rock water-wet.

A unique environment friendly asphaltene remover system has been developed capable of maintaining long-term production rates and by leaving the rock in a water-wet condition. Flash point of this system is higher (> 145° F or 62.7° C) than the traditional solvent systems, allowing to perform pumping operations in a safer and environmentally friendlier way.