bluuebunny/crossref_metadata_2025 huggingface dataset:
Experimental Investigation of Hydraulic Fracturing on the Montney Formation
Authors: Safari Reza , Albert Richard , Laycock Dallin
Published: September 2022

To assist in understanding the role of rock fabric, stress state, and fracturing fluid viscosity on fracture geometry, four large, dry blocks (28" × 28" × 36") sourced from a Montney formation outcrop were hydraulically fractured in a series of laboratory experiments. These tests investigated the role of texture on hydraulic fracture (HF) propagation with different fluid viscosities, and strike-slip and normal stress regimes. Each block was hydraulically fractured in two stages to allow comparison, within the same overall rock fabric, of fractures created by the different viscosities and injection rates. Pre-existing discontinuities, including calcite-cemented fractures and calcite layers were mapped prior to the test by a goniometer. The static elastic properties, failure parameters, dynamic properties, and fracture toughness of the host rock were measured in detail. During each test, the HF propagation was monitored by recording the generated acoustic emissions. Subsequently, the blocks were carefully dissected, and HF geometries were mapped in detail by laser profilometry.

The results showed that heterogeneity in the rock texture and its location had a primary effect on the fracture propagation. The direction of the maximum stress played, at best, a secondary role. The fracture dynamics determined with acoustic emissions indicated a relatively symmetric, pancake-like shape with high dimensionless viscosity and more asymmetry with low viscosity fluid. Visual inspection of the resulting fractures showed truncated elliptical shapes with both viscosities and with the higher viscosity having less containment. Acoustic emissions clearly indicated HF initiation, propagation, and interaction with the rock fabric, indicating arrest and spreading along pre-existing interfaces in cases of low dimensionless viscosity, and more uniform propagation in cases of high viscosity but with the rock fabric having a significantly reduced impact.

The experiments demonstrated the likelihood of the substantial impediment to successful proppant delivery and hydrocarbon production in the field based on observed occurrences of HF arrest on pre- existing interfaces (indicating possible height containment) as well as the formation of branches and step- overs. Our results indicated that sufficient knowledge of the fabric, in conjunction with proper selection of injection fluid and rates, may provide additional height containment and hence enhance lateral fracture extension and improve the depletion of the pay zone. Ultimately, optimum production may more likely be achieved with collection of further rock samples, laboratory testing, and modeling of pre-existing interfaces to allow relative ranking of these barriers.
Professional Development of a Production & Facilities Generalist as a Jack-of-All-Trades
Authors: Pearson Robert , Brindle George , Anifowose Babatunde
Published: September 2022

This paper looks at the Professional Development of a Production and Facilities (P&F) Generalist ("a Jack-of-All-Trades"). It discusses the criticality of Continuous Professional Development (CPD) and how to take advantage of the SPE Volunteer Opportunities and Programs (Training Services, Competency Development Matrices, and the Competency Management Tool (CMT)).

Most professionals in the SPE Production & Facilities Community graduate with variety of Science, Technology, Engineering and Mathematics (STEM) degrees and many pick up applied Petroleum Engineering and Project Management knowledge on the job.

The SPE Competency Matrices provide a framework for developing:

A minimum Breadth of Knowledge either as an undergraduate or during the first year of employment in the Exploration & Production (E&P) Sector of the Energy Business. A minimum Depth of Knowledge, acquired over the first 4-5 years or so, in General Engineering and their chosen (or assigned) Technical Function, in this case, either Production & Operations (P&O) or Projects, Facilities & Construction (P, F & C).

The mid-career period is often a time of significant turbulence and confusion with many generalists testing-out or being assigned to a variety of roles, such as Subject Matter Experts, Team Leads, Supervisors, and Project Managers, or with other functions and/or new companies before settling on a longer-term career path.

Traditional paths for knowledge development are further complicated by an increased focus on Data Science & Engineering Analysis (DSEA), Sustainability, Decarbonization, and the Energy Transition, along with a need to reinforce our Social License to Operate.

The largest corporations and major training organizations, including the SPE, provide Competency Management Tools to help practitioners identify proficiency gaps and training requirements for a current or anticipated future assignments. Similarly, the SPE provides ongoing support not only with Business Management Leadership (Soft Skills) Training but also through the Technical Communities and Sections. In the final analysis, most P&F Generalists are "value-creation professionals" who just happen to work in the Upstream Oil & Gas Industry and have working knowledge of the acronyms and terminologies typically used in our profession.
Is Smart Water Flooding Smarter Than Seawater Flooding in a Fractured Chalk Reservoir?
Authors: Puntervold Tina , Khan Md Ashraful Islam , Torrijos Iván Darío Piñerez , Strand Skule
Published: September 2022

It is well-known that seawater flooding has been a huge success for hydrocarbon recovery from the fractured chalk reservoir, Ekofisk, on the Norwegian Continental Shelf. Extensive laboratory studies the last decades have shown that Smart Water flooding has potential of greatly improving oil recovery beyond that obtained by standard waterflooding, due to wettability alteration, which improves reservoir sweep efficiency. However, to be economically viable compared to seawater injection, the Smart Water must be cheap, easily available, and must substantially improve oil production. Thus, the objective of this work was to investigate if a tailor-made, but cheap Smart Water could enhance oil production compared to seawater injection in an offshore chalk reservoir. Is seawater the smarter choice in offshore chalk reservoirs?

Two reservoir chalk cores were used in this study and initial reservoir core wettability was estimated from optimized, in-house laboratory core restoration procedures. The potential for wettability alteration and resulting oil recovery by seawater (∼33000 ppm salinity) and Smart Water (<5000 ppm salinity, containing 20 mM SO42-, Ca2+ and Mg2+) were compared in spontaneous imbibition tests at reservoir temperature (>100 °C). Waterflooding at various rates was also performed to evaluate the displacement performance, with regards to water breakthrough and ultimate recovery, of the two injection brines studied.

Reproducible initial wettability was confirmed in both reservoir cores, making a comparison of brine performance easier in spontaneous imbibition tests. The restored cores behaved initially mixed to oil-wet, imbibing limited amount of water. Both seawater and Smart Water showed potential for wettability alteration, although oil recovery by spontaneous imbibition by Smart Water was not improved compared to that by seawater. By low-rate waterflooding the Smart Water was more efficient than seawater due to the water being forced into the interior of the cores causing faster and more pronounced wettability alteration at microscopic scale, hence generating stronger positive capillary forces than in the spontaneous imbibition process. It was concluded that Smart Water flooding can potentially improve recovery beyond that obtained by seawater flooding in fractured chalk reservoirs.

This high-temperature offshore chalk reservoir case study demonstrates that seawater is able to alter wettability of mixed to oil-wet reservoir chalk in a similar way as previously reported for outcrop chalk. Additionally, although seawater injection seems to be a good choice offshore, there is still potential of tailoring a Smart Water composition to both accelerate oil production, delay water breaktrough, increase ultimate oil recovery, thus lowering the field residual oil saturation if its injection is timely implemented.
Improving Alkali Polymer Flooding Economics by Capitalizing on Polymer Solution Property Evolution at High pH
Authors: Födisch Hendrik , Nurmi Leena , Hincapie R. Rafael E. , Borovina Ante , Hanski Sirkku , Clemens Torsten , Janczak Alyssia
Published: September 2022

Alkali Polymer (AP) flooding is a promising Enhanced Oil Recovery (EOR) method to increase oil recovery from reactive oils. It is essential to carefully select the alkali and polymer type and concentration to optimize incremental oil recovery. In addition to the conventional laboratory tests for polymer flooding, the effects of the high pH on the polymer and its evolving properties over time need to be investigated. Consideration of near-wellbore and reservoir effects is a key in designing the process. We are showing how understanding and taking advantage of the polymer performance in a high pH environment allows to reduce costs, increase injectivity and incremental oil recovery for AP projects.

The polymer performance was evaluated for AP flooding of the Matzen field (Austria). Evaluations included changes in polymer rheology during aging at high pH conditions, phase behavior tests, and single/two-phase core floods with aged and non-aged polymer solutions. In addition, adsorption of the aged polymer and interfacial tension was measured. The aging was studied in anaerobic conditions at reservoir temperature and through an accelerated method at elevated temperature. The degree of polymer hydrolysis over time was determined via NMR and linked to viscosity performance.

The AP conditions in the Matzen AP flooding project (pH > 10) lead to an increased initial rate of polymer hydrolysis of the tested HPAM by a factor of 100 compared to hydrolysis at a neutral pH level. This resulted in a rapid increase in polymer solution viscosity of 160 % compared with initial conditions within days at reservoir temperature of 49 °C, after which the increase leveled off. Accelerated aging experiments at higher temperature predict long-term stability of the increased viscosity level for several years. Single-phase injection test in representative core confirmed the performance of the aged solution compared to a non-aged solution at the same polymer concentration. The retention of polymers is reduced in AP conditions compared with traditional neutral pH conditions. Two-phase core flood tests showed the increased polymer viscosity at reservoir conditions. The displacement efficiency of the aged and non-aged polymer solution was similar confirming the potential for cost savings using lower polymer concentration and making use of the increased polymer viscosity owing to hydrolysis.

The results show that the design of alkali polymer projects needs to take the changing polymer rheology with time into account. The costs of alkali polymer projects can be reduced owing to the lower required polymer concentrations for the same displacement efficiency and reduced retention of polymer. An efficient design of alkali polymer projects takes good injectivity of non-aged polymers and the aging of the polymer solutions in alkali into account.
Pioneering Subsurface Data Management Studio and Asset Retirement Obligation Retrenchment in Upstream South Sumatra Region, Indonesia
Authors: Permana Aziz , Sulaksono Aji , Hikmah Nurul , Dwiyono Imam , Pratama Ridho , Gustian Yan , Suseno Pambudi , Parsaulian Sakti
Published: September 2022

According to the geoscientist work profile in Oil & Gas Journal, 1998, inadequate data management practice has caused 60% proportion of the time to be spent for data searching and compilation, it has consequently reduced time for appropriate subsurface analysis. The oil and gas industry in the South Sumatra region is categorized as a matured working area and always becoming a challenge to operate efficiently, not only because of well-developed fields and depleted reservoirs, but also commonly deals with a huge amount of old raw data set, either well coordinates, seismic, trajectory, or log data, even data duplication itself. However, since its first discovery in 1896, the South Sumatra region has already transformed into one of the most productive basins in Indonesia until the present through immense exploration and development activities. Additionally, more than 4000 wells have been drilled in 86 oil fields of the South Sumatra block within an 18,181 km2 working area. Massive operational jobs such as drilling programs, workover, and well intervention involved a lot of subsurface data. Invalid data has proven a serious problem that caused several operational failures and enormous financial losses. Proper implementation of subsurface data management for the last several years has generated significant progress for future company milestones.
A Coreflood Simulation Study of a Systematic Co2 Huff-N-Puff Injection for Storage and Enhanced Gas Condensate Recovery
Authors: Seteyeobot Ifeanyi , Jamiolahmady Mahmoud , Doryanidaryuni Hosein , Molokwu Victor
Published: September 2022

Recently some core flood experimental data were reported following a new CO2 Huff-n-Puff (H-n-P) injection technique. This technique optimized CO2 injection pressure and volume to improve CO2/resident fluid interactions for enhanced gas and condensate recovery and CO2 storage purposes. This simulation study aims to complement and generalize the corresponding core flood experimental results. The simulation data confirm the dominant governing mechanism and the importance of using appropriate CO2/gas-condensate kr data while accounting for the effect of compositional changes on gas and condensate mobility during CO2 H-n-P injection.

Laboratory PVT tests were performed to generate relevant data sets that describe the complex phase behavior changes when CO2 interacts with gas condensate systems. These data sets were applied for EOS tuning, phase behavior prediction, and quantifying the level of CO2/gas condensate interactions. A CO2 H-n-P injection core-flood simulation model was developed. H-n-P injection cycles with the incremental injection of CO2 volumes were simulated to replicate experimental procedures performed on a high-permeability Berea sandstone core.

Experimental data showed that conventional CO2 H-n-P injection treatment significantly improves hydrocarbon gas and condensate recovery efficiency but at the cost of injecting and producing high volumes of CO2. While the proposed method applied at the maximum condensate saturation for the corresponding CO2/gas-condensate mixture can match the recovery efficiency achieved when applying the conventional injection technique, but with much lesser volumes of CO2 injected and produced.

The relative permeability data measured for gas and condensate fluids (GC-kr) were significantly affected by the compositional changes resulting from CO2/resident fluid interactions below the saturation pressure. The numerical model predicted a close match for the pressure profile after adjusting the GC-kr data. However, it could only match the production profile for the pre-CO2 and first CO2 injection cycle, where the volume of CO2 injected was small and had a negligible effect on condensate recovered relative to the volume of condensate in place. Sensitivity analyses were performed on GC-kr data attempting to history match the experimental and simulated data. The generated data were analyzed to quantify the effects of CO2/resident fluid interactions on condensate revaporization and the model's predictability. These data will aid in bridging the gap in the level of CO2/gas-condensate interactions during CO2 flooding, which is vital for designing an efficient CO2 H-n-P injection process.
General Considerations for the Use of Offshore Depleted Reservoirs for CO2 Sequestration
Authors: Amirlatifi Amin , Ovalle Adriana , Bakhtiari Ramezani Somayeh , Mohamed Ibrahim , Abou-Sayed Omar
Published: September 2022

Carbon dioxide (CO2) sequestration is one of the most effective ways of overcoming the excessive emissions of anthropogenic CO2 and the resulting climate change. The existence of large and accessible pore space, along with the wells, pipelines, and surface facilities, makes depleted oil and gas reservoirs a prime target for the deposition of CO2. This study aims to outline the primary considerations for sequestration of CO2 in abandoned oil and gas reservoirs, with a particular focus on offshore reservoirs in the Gulf of Mexico (GOM).

We examine publicly available data from the Bureau of the Ocean Energy Management (BOEM) to gather insight into the existing porous formations in the GOM. Particular interest is given to the formations that have been assessed, developed, and are now abandoned. This approach has enabled us to identify significant storage potentials in shelf, shallow and deep parts of the GOM, making it possible to offer an abundance of safe and long-term storage options in this region.

The first productions in the GOM started back in 1947. As of January 2018, over 900 GOM fields, including more than 5,000 reservoirs (also known as "Sands"), have since ceased production. The total pore volume of these reservoirs is over 175 million cubic feet or over 6.1 million cubic meters. Although many of the wells in these reservoirs are permanently plugged and abandoned (P&A), the existing knowledge about the pore space, the presence of proven seal and geomechanical stability, and the favorable depth of such sands are still highly relevant to commercially viable CO2 sequestration scenarios. Such knowledge can provide a wealth of knowledge, which had to be acquired otherwise prior to the development of the sequestration project.

The present paper offers an overview of the potential CO2 sequestration candidates in the GOM and practical considerations for commercially viable and environmentally friendly sequestration sites. We examine the main factors contributing to the safety and sustainability of long-term storage and sequestration projects, along with remedial techniques that would pave the road for commercial leasing of pore space in the GOM for safe and effective disposal of CO2.
Accelerating Pipeline Corrosion Modeling via Bayesian Active Learning
Authors: Zhang Shun , Lu Ligang , Yang Huihui , Tsai Kuochen , Sidahmed Mohamed
Published: September 2022

Pipeline corrosion poses signiﬁcant challenges and risks to the energy industry and its mitigation requires extensive and reliable predictive modeling. Corrosion models based on computational ﬂuid dynamics (CFD) stands as a desirable candidate for its detailed physical characterization and modeling ﬂexibility, but its applications in practical industrial settings is limited by the high computational cost and laborious manual operation in the modeling and sampling process. To address these challenges, we propose a Bayesian active learning method. The method consists of a surrogate model formulated using Gaussian process regression (GPR) to provide rapid model prediction as well as uncertainty quantiﬁcation, and an adaptive sampling scheme to automate and accelerate the data collection process. Careful dimension reduction guided by both physics and data is also carried out to signiﬁcantly simplify the sampling space. The capability of the overall method for eﬃcient and automated sampling and surrogate modeling is demonstrated on an example case of corrosion predictive modeling and can be leveraged in industrial applications at a much larger scale.
Electro-Hydraulic Servo Actuation for Well Completions
Authors: Lerner Daniel M. , Orban Andre E.
Published: September 2022

Objectives/Scope

Well Completions are challenged with the demands of managing increased multiple production zones.

This paper addresses a solution to these issues:

Reduce the number of hydraulic control lines.

Provide independent production zone flow control.

Support a multiplicity of hydraulic actuated devices.

Methods, Procedures, Process

These Well Completion challenges are addressed using networked Electro-hydraulic Servo Actuators (EHSA). The EHSA is a small diameter, closed loop, hydrostatically balanced electro-hydraulic actuation system. EHSA has a feature set to support intelligent and autonomous multizone Well Completions. Each EHSA servo provides controlled operation of a device at a remote endpoint downhole.

Bidirectional flow is obtained directly from the rotation of the pump and motor, eliminating the use of check, relief, and solenoid valving. Measured flow and pressure provide incremental precision positioning.

Multiple hydraulic control lines are eliminated.

Results, Observations, Conclusions

Years of extensive testing programs validated reliable and consistent operations verified in hydrostatic autoclave stress test equipment. EHSA tests demonstrate years of operation, estimated to meet or exceed 20 years of operation.

The system operates with electrical wires providing direct command/response capability and power. A single TEC line can support a multiple EHSA network.

Alternately, pressure pulse commands can be transmitted from the surface to control each battery powered EHSA. Autonomous control in response to sensor inputs allows for adjustment of the well control devices, for instance in response to well pressure changes. A real-time clock provides for a predetermined schedule of operations, possibly combined with

command/response, autonomous control, and sensor measurements.

Self-balancing eliminates hydraulic lock by uniquely adding or disposing of fluid imbalance with the hydraulic reservoir. The positive displacement operation is calibratable and proven highly repeatable.

Remedial override is inherent in the EHSA because there are no valves.

Novel/Additive Information

The EHSA is a multiple-use hydraulic engine with intelligent control features for various types of completion devices either single-use or permanent installation.
Digital Tool Allows Simultaneous Operation and Facilities Optimization in Limited-Budget Projects
Authors: Gonzalez Muro Luis , Calderon Ruiz Diego , Fun Sang Robinson Byron , Florez Florez Fabian
Published: September 2022

This paper presents an example of how small oil fields can approach digital transformation aiming higher digital maturity and becoming a "smart asset". The asset targeted to integrate the well performance and the available capacity of the existing processing facilities, and with that allocate resources to actionable optimization opportunities. The optimization is driven by allocating the facilities volume (in oil) to those wells with higher oil output.

The methodology uses the classic well by well production optimization approach (find the highest incremental oil with the lowest investment), the novelty is to rank the wells based on the main bottlenecks of the processing facilities. In this way the ranking of the wells is dictated by the overall production system analysis from the pore to the export pipeline.

Once a constraint is identified a baseline is set and a target status is defined. The gap between current and target states is overcame by robust data structure that enables business and artificial intelligence workflows for well and facility smart analytics.

The enhanced workflow allows surface facilities surveillance in a relative high frequency, this in combination with the well monitoring improve optimization decision dramatically.

As a result, this strategy has allowed the asset to reduce 900 man-hours a year, reduce operative production losses by 40%, lessen artificial lift failure events rate by 40%, increase production in the order of 5% (in a 9K BOPD asset), bringing the project to outstanding production levels. Furthermore, this solution has indirectly helped to reduce CO2 emissions in at least 20 Tons per year, reducing the carbon footprint in a sensitive environmental area in the amazon forest.
Understanding and Preventing Incomplete Shunted Open Hole Packs in Trinidad's Colibri Field
Authors: Tibbles Raymond , Wassouf Phil , Govinathan Kesavan , Campbell Patrick , Daniel Vijay , LaPointe Michael , Rattananon Pichate , Zhang Ying
Published: September 2022

Three out of four shunted gravel packs in Colibri suffered from severe losses near the end of the gravel pack and failed to achieve a final screenout even though as much as 50% excess gravel was placed. This study uses reservoir, completion, and bottom hole gauge data to understand why the final screenout was not achieved and how to ensure complete packing/final screen-outs in the future. The evaluation started with building representative models for each well in a gravel pack simulator to predict the pressures and packing mechanisms downhole. The data used in the models included the relevant completion and reservoir data. The model was then used in conjunction with the treatment records (surface pumping data and bottom hole gauge data) to evaluate the packing extent and sequence for different parts of the openhole. This evaluation pinpointed the time and location where losses occurred as well as the extent of openhole packing in each section. Various theories were formulated to describe the observations and one theory was selected as the most likely. The evaluations showed a consistent packing behavior across all the wells in which the screens were initially covered without the aid of shunts from toe to heel with much less gravel than required to fill the annulus void. After this initial packing stage, shunt packing began, and additional packing in all of the sections occurred. During this part of the packing process, losses began which resulted in all of the final slurry exiting the open hole into the reservoir. Based on the analysis, the most likely cause of the strange packing behavior was the combination of low screen inflow area, relatively low gravel permeability, higher fines content in the natural gravel sand and high gravel carrier fluid viscosity, which resulted in a high pressure drop across the pack/screen interface. The one well which achieved a final screenout had a lower pumping rate, resulting in lower pressure drop.
Experience of the Development and Implementation of Cognitive Technologies for the Serbian Upstream Oil Industry
Authors: Naugolnov Mikhail , Micic Ponjiger Tanja , Zalevskii Nikolai
Published: September 2022

The work is devoted to the experience of creation and implemention of digital solutions in the Petroleum Industry of Serbia (Serbian: NIS). The paper detaily examines digital projects which applied data science, machine learning/deep learning in seismic, petrophysics, geology, reservoir engineering and production technology. These projects aimed to solve current challenges of brown fields at a late stage of operation, as well as in working with sand-bearing well stock, control of scale and efficient development of fractured reservoirs.
Bioremediation Study on Formation Damage Caused by Hydraulic Fracturing: A Microfluidic Approach
Authors: Liu Songyuan , Sie Chao-yu , Malekahmadi Fatee , Lu Bo , Li Yifan , Fan Cara , Zhang Xinyue , Serediak Owen , Fortin Jelayne , Abedini Ali
Published: September 2022

Hydraulic fracturing has been applied to unconventional reservoirs with low permeability to achieve higher productivity and economic potential. However, polyacrylamide-based friction reducer and guar gum, two of the most common components in fracturing fluid could cause formation damage by penetrating into the matrix and blocking the flow path. To regain the conductivity of the damaged area, a bioremediation method was developed and validated by a microfluidic approach. Modified nutrients were used to stimulate the indigenous bacteria that could consume or break the polymer residues.

Indigenous bacteria were extracted from oil field produced water collected with customized anaerobic sampling kits which have been sterilized. Feasibility studies were conducted to investigate the indigenous bacteria activity with and without nutrient supply. Fracturing fluid, field water, and a modified nutrient recipe which contained 300 ppm of inorganic salts were loaded into anaerobic sample vials in a 140°F - 150°F incubator. Microfluidic tests were performed in 150°F oven with microfluidic chips designed and fabricated based on the topology of matrix networks. Fracturing fluids were injected into a chip saturated with field water to simulate formation damage. Remediation fluid consisting produced water, injection water and nutrient was injected into the chip. After two weeks soaking, 2% KCl brine was then injected into the chip at 200 nl/min until a stable pressure drop was achieved. Microscopic pictures were taken before and after soaking to demonstrate the polymer damage and the remediation of microfluidic chips.

The indigenous bacteria were successfully stimulated with and without the existence of the friction reducer based on the results of feasibility tests. Microfluidic tests showed there is a significant difference in precipitations between the case with and without nutrient supply, which indicates that the bioremediation method could regain conductivity of the damaged formation.

This work is novel research on bioremediation application in unconventional reservoirs with only indigenous bacteria involved. The customized sampling technology and laboratory approach could prevent contamination of other microbes and oxygen, which could improve the quality of the research. Microfluidic chip is a great simulation of porous media and a proof of concept between scientific hypothesis and field application which requires small sample size and provides good reproducibility. In field applications, only an extremely low amount of nutrient is required in this process which provide great economic potential. Additionally, the injected nutrients will be fully consumed by the bacteria which makes this technology is an Environmental, Social and Governance (ESG) approach in energy industry.
Unlocking Solutions in Oil Field Production: Innovative & Advanced Autonomous Flow Control Device application.
Authors: Martinez Santiago Maryvi , Ortiz Jhon , Bethapudi Bhanu , Noordin Firdaus , Trisnadi Dicky , Mohammed Tawheed , Al Obeidi Mazna , Permana Krisna , Soufi Abdulrahaman
Published: September 2022

As a result of Reservoir Monitoring Plan, a Non-uniform Saturation has been identified in the Southern part of the reservoir. High gas saturation, coming from gas injection in underlying units, was observed within the first 10 to 30 Ft. TVD of top-most section of the reservoir. Therefore, in order to mitigate the potential problems that this gas production can generate on the well production performance which could shorten the well productive life, a flow control strategy was implemented in the lower completion designs of six new drilled wells.

Following the best practices as per ADNOC Standard Operating Procedure and after performing an opportunities screening, inflow control device ‘ICD’ was found as the technology to be used on these cases. A steady state modelling was performed for identifying the most suitable ICD design for the new wells drilled during 2021-2022. In order to consider the changes on the reservoir fluid conditions over time along the wellbore, a sensitivity analysis was conducted during the steady state modelling. Likewise, the final ICD design took into account that production profile should be adhered to reservoir management guidelines.

The result of wellbore simulations provided insights about the optimum solution for the well completion. This called for both adequate well positioning along the reservoir section and the utilization of ICD technologies as a means for GOR control, making feasible a more efficient practice for well and reservoir management.

A successful trial of installing the first Autonomous or self-regulating ICDs have been completed and deployed as an innovation in the field to optimize and balance downhole influx profile, which will allow to minimize the impact of the gas breakthrough GBT while maintaining wells productivity.

Overdesigned ICDs was avoided since they not just increase the cost of well completion, but also will impact the well performance negatively. Most of wells with segmented completion with Autonomous Inflow control Device AICD pertaining to PAD drilling project, will be commissioning in Q2 2023. One out of the six wells is currently flowing and an evaluation program and results will be further discussed in this publication.
Extensive Laboratory Test to Validate Material Selection for CO2 Injector in Depleted Carbonate Field - A Case Study of Carbon Capture and Storage Development Project in Offshore Malaysia
Authors: Abu Bakar Mohd Azuan , Riyanto Latief , W Mohamad W Amni , Moh Wahi M Wahidullah , A Halim Rahimah , Kamitani Hiroki , Amaya Hisashi
Published: September 2022

As part of decarbonization initiatives, the K1 field CCS project plans to capture the CO2 produced from the nearby gas field development and store it in the depleted carbonate reservoir. One of the challenges in CCS project is to choose the optimum material for the well design. This paper presents the case study of CO2 injection well material selection of K1 field CCS project development.

The injection fluid contains more than 90-98% CO2 and about 500-711 ppm of H2S. This condition and presence of free water might create high risk environment for Stress Corrosion Cracking (SCC) and Sulfide Stress Cracking (SSC). Materials were initially screened based on Oil Company Tubular Good (OCTG) charts. Further qualification was deemed required through fit for purpose tests which represent the most likely and worst-case conditions. Test matrix has been developed based on NACE TM 0177 and NACE TM 0136 guidelines.

Initial material selection using the OCTG chart suggested 25 Cr as a suitable material. No verification through the lab test is required for this material. As an alternative material, 22 Cr and enhanced 13 Cr were considered, subject to further verification on Sulfide Stress Cracking (SSC) and Stress Corrosion Cracking (SCC). The test matrix had been developed to simulate two scenarios where the injected gas mixes with condensed water during injection and flowback of formation water. For enhanced 13 Cr material, SSC test is performed at 24°C and 34°C. The temperature of 24°C is chosen as the temperature of highest susceptibility of SSC expected to occur for martensitic material. For temperature of 34°C, it is performed to investigate the effect of supercritical CO2 fluid phase on the corrosion and cracking if any. For 22 Cr which is duplex material, the test is performed at temperature of 90°C, which is the temperature of the highest SSC susceptibility of duplex material expected to occur. The corrosion and cracking test result show that the material suitable for more than 90% CO2 with about 711 ppm of H2S in condensed water condition and flowback fluid condition is 22 Cr and above grade.

As part of material selection process, extensive lab tests to qualify tubing material has been performed by both OCTG manufacturer and independent lab. The result enables further optimization on well cost while giving assurance on K1 CCS injector well's integrity
Neutral-We Proppant Improves Post Treatment Cleanup and Enhances Productivity
Authors: Kortam Mostafa , Sobhi Ihab , Khalil Mahmoud , Yahia Omar , Spurr Naima
Published: September 2022

A well, with very low bottomhole pressure, required frequent workover operations due to pump failures from sand production. A gravel pack was designed to minimize the production sand issues. However, to sustain low pore pressure (less than 0.1 psi/ft) without affecting well productivity, lower drawdown was needed during an acceptable sand control completion. This presented a challenge due to massive completion brine losses and increased risk of formation damage. These challenges could create impairment in well productivity. Usually, a rig utilizing coiled tubing is used to handle the flowback and unload the well.

To increase the amounts of flowback fluid, and minimize formation damage, the completion of this well used a neutral wet proppant. The proppant, which had surfaces that are neither oil nor water wet, was used in this gravel pack to improve the flowback fluids recovery. The expected benefits of this proppant were to (1) eliminate capillary pressure within the proppant pack and (2) alter the interaction between aqueous/organic (hydrocarbons) and the proppant surfaces. This would be accomplished by decreasing the intra-molecular interactions between the fluids and the proppant surfaces thus resulting in improved flow compared to native surfaces.

Lightweight ceramic (LWC), neutral-wettability proppant was used to improve clean-up and enhance fluid flowback recovery. Extensive laboratory testing on the proppant was performed ahead of the job, including properties and compatibility with stimulation fluid. This proppant had both hydro- and oleophobic properties. The hydrophobic properties improve the flow of the aqueous fluids, while the oleophobic properties improve the flow of the hydrocarbon phase. The proppant was pumped similarly to any other conventional proppant and no changes in the procedures were needed. After completion of the job, the well was shut-in and the flowback un-loading was performed a week later. This completion relied on using ESP to perform the cleanup and producing the well concurrently to reduce the operation time and cost spent during well unloading.

After completion, 100% of all pumped brine was recovered leading to an enhanced production rate with no impairment or coiled tubing lifting post treatment required. The cleanup was carried out after one week from the treatment date. The well cleanup, in comparison with wells that used conventional proppant, was much faster and saved $50,000. The calculated productivity index is 3.2 compared with 2.8 bpd/psi before the treatment representing 15 % gain. No sand production was observed during production performance nor seen in the wellbore during pump replacement after two years of continuous production period. The average run life prior to this treatment was 3 months, thus impacting not only the well productivity but also the run well life.
Innovative, Cost Effective and Zero Flaring Solution to Clean-Up and Start-Up New Wells in High H2S Field in Kazakhstan. The Vital Step Forward Towards Net Zero Carbon Footprint
Authors: Tankiyev Timur , Kartamyssov Aidyn , Zhumabayev Bolat , Izbassov Arman , Bissakayev Beibit , Hosatte Pierre , Burkitov Ulan , McGachy David , Privitera Salvatore , Itoua Rolle , Kydatov Mikhail , Kurmanbayev Altay , Akbayev Beibit , Osokin Ivan , Kaipov Yermek , Valdivia Paulo G. , Zhandin Alexander
Published: September 2022

Flaring has received significant attention over the past few decades and has become a major concern for many operators today. One of the contributors to hydrocarbon flaring is well clean-up operations, where traditionally oil and gas are disposed by flaring at the wellsite.

This paper will share in details how integrating various technologies allowed to come up with a cost effective, zero flaring solution for well clean-up operations, that substantially reduced overall field carbon footprint.

A common alternative to flaring is to store the crude in tanks and/or pump crude into production line, if available. However, the associated gas is typically flared off, as using gas compressors to inject gas into production line is extremely cost intensive and operationally complex.

As an alternative, fit for purpose multiphase pumps, specifically designed to handle clean-up operations and combined with a high pressure surface well testing package proved to be a successful, innovative and cost effective solution to bring new wells to production without gas flaring. The pumps, installed at the inlet of a high-pressure separator, boost the pressure such that both oil and gas can flow directly into the production line, while water and spent acid from well stimulation treatment are separated out onsite into water tanks.

The method does not require any hydrocarbon flaring, thereby drastically reducing emissions for well clean up and start up operations. The solution enabled a reduction of an average of 24 Kilo-Tonnes of CO2 equivalent of emmissions per well clean up, when compared to 100% flaring, resulting in a very significant and measurable positive environmental impact.

The pumps proved to be reliable and fit for purpose, by toleranting high gas-volume-fraction (GVF) conditions and unstable flow, which is vital for clean-up operations. In addition, the setup proved to be an efficient pressure-boosting package, to gain additional production, by overcoming the high backpressure from the production lines network. The package was introduced in the giant Karachaganak oil and gas condensate field in Western Kazakhstan in high H2S environment, and was used in 13 wells over a two-years period, resulting in significant net production gains for the operator.
Pilot Program for Digitally Validating Well Barrier Integrity During Inflow Testing
Authors: MacDonald Cody , Cully Rick , Franklin Mark , Flenoy Donald
Published: September 2022

Inflow (negative) tests are critical for verifying the integrity of well barrier elements (WBEs) that prevent unwanted flow of formation fluids into the well. Historically, inflow tests have been validated and documented using subjective and inconsistent techniques, including analog circular chart recorders and hand-written notes. The consequences of misinterpretation of test results can lead to catastrophic well control events. This paper presents the results of a major oil & gas operator's pilot program to standardize the use of closed system testing and a digital analysis application as a global solution to improve the safety and efficiency of inflow tests.

The pilot program was deployed on multiple drillships in the U.S. Gulf of Mexico. Each test involved displacement of drilling mud with lower density test fluid followed by a series of bleed down steps to incrementally reduce the hydrostatic pressure above the WBE until it was less than the formation pressure from below. The displacement and bleed-down steps induced complex thermal effects on the fluids in the wellbore, complicating pressure analysis and leak detection. The digital analysis application used research-based algorithms capable of differentiating between thermal effects on the fluids and a leak. The application provided an objective and transparent pass-fail determination for each test.

The software was installed at the rig sites, coupled to surface pressure data acquisition equipment, and configured to evaluate tests per BSEE-accepted criteria. Test progress and results were transmitted to a cloud-based service, enabling teams to collaborate and view critical tests in real-time. Test records were archived automatically, and digital records were preserved in comprehensive and standardized reports, ensuring knowledge transfer throughout the well's lifecycle. The test results were 100% in agreement with the operator's own pass/fail analysis results, which was one of the key success factors of the pilot. Notably, the time savings were significant. Historical inflow tests ranged between 4-12 hours for this operator, while the average total time for the pilot using digital inflow analysis was less than one hour.

The pilot program proved that using a closed system method and the digital application's inflow analysis algorithm provided direct information about the thermal effects of fluid displacement and bleed-down phases resulting in more accurate and efficient inflow tests that improve safety and well integrity assurance.
New Approach for Stress-Dependent Permeability and Porosity Response in the Bakken Formation
Authors: Ouadi Habib , Mellal Ilyes , Chemmakh Abderraouf , Djezzar Sofiane , Boualam Aldjia , Merzoug Ahmed , Laalam Aimen , Mouedden Nadia , Khetib Youcef , Rasouli Vamegh , Tomomewo Olusegun
Published: September 2022

During the reservoir depletion and injection operations, the net effective stress is disrupted due to pore pressure changes. As a result, the reservoir properties, mainly porosity and permeability, are influenced by the change in the stress behavior in the reservoir rock. Understanding the porosity and permeability stress-dependent alteration is crucial since it directly impacts the reservoir storage capacity and the production/injection capabilities. Conventionally, lab experiments are conducted to understand the stress dependency of porosity and permeability magnitudes. Two methods are usually used: the unsteady-state method (Core Measurement System, CMS-300) and the steady-state method (Core Measurement System, CPMS). The challenges with these experiments reside in the fact that they are expensive and time-consuming and may cause the destruction of the core samples due to the applied stresses.

This study aims to investigate the effect of stress variations on porosity and permeability changes. These properties were measured on a total of 2150 core data from the three members of the unconventional Bakken formation (upper, middle, and lower), applying 35 different Net Confining Stress (NCS) values, ranging from 400psi to 5800psi. A correlation was formulated between permeability and the NCS to illustrate the stress dependency relationships. The Grey Wolf Optimization algorithm (GWO) was used to tune the correlation for the Bakken formation. Machine Learning methods were also applied for the porosity and permeability stress dependency response prediction, which are as follows: Linear Regression (LR), Random Forest Regression (RF), XGBoost Regression (XGB), and Artificial Neural Network (ANN).

The results demonstrate that the porosity and the permeability decrease with the increase of the NCS and vice versa. The permeability is highly sensitive to the NCS changes compared to the porosity. The developed correlations showed a good fit with the data extracted from the laboratory experiments of the pilot well. For the data-driven models, the coefficient of correlation R2-Score ranged from 91% to 93%.

These models can be used to constrain the modeling work and reduce the uncertainties by introducing the effect of the net effective stress changes during reservoir depletion/injection on petrophysical properties.