bluuebunny/crossref_metadata_2025 huggingface dataset:
Supervised Machine Learning for Liquid Rate Estimation in Oil Field with Limited Well Monitoring Data: A Case Study of the Handil Oil Field
Authors: Setiadi Rahman , Hidayat Masun , Mardin Mursalim
Published: February 2024

Handil is an oil field located in the Mahakam swamp area. Approximately 80% of its wells are operated with gas lift. Well surveillance primarily relies on pressure, temperature, and gas injection measurements, which are locally updated through daily operator visits. In some wells, an additional single-phase orifice meter is installed on the flow line to estimate gas rates, but it doesn’t provide any information on liquid rates. Mobile testing units, mounted on floating barges, conduct well tests on a campaign basis every 3 to 6 months. However, daily liquid production monitoring becomes extremely challenging due to the lack of metering references at the well level. Furthermore, fast sedimentation area restricts the mobile testing unit to approach the well cluster which further extend the well potential’s uncertainties.

Supervised machine learning techniques were employed to estimate the liquid rates of the wells based on available surface parameters. Two machine learning models were developed: liquid rate prediction based on wellhead parameter data (well head estimate) and gas rate correction on water-out gas well based on orifice parameter data (orifice estimate). The preprocessed datasets consisted of clean 930 well test data for the well head estimate and 167 data for the orifice estimate. They were consisted of actual well production test data (wellhead pressure, temperature, gas injection rate, real gas rate, liquid rate, and water-cut), additional flow line parameters for the orifice estimate (flow line pressure, temperature, orifice differential pressure, beta ratio), and the open reservoir depth. The datasets were used to train and test different regression methods, including linear regression, polynomial regression, support vector machines (SVM), and random forest. Random forest regression, providing accuracy up to 93%, was selected on both ML model. Furthermore, additional polynomial regression was applied for model reinforcement, avoiding over-fit and flat prediction on the blind data beyond the training set range.

The results show that the developed machine learnings increase the field daily liquid rate production allocation accuracy at 90% from previously only 80% compared to real produced liquid, better detect liquid production decline or incline following dynamic well parameter for quick necessary action, provide new insight to sand production avoidance on specific sand control type, and accurately provide gas correction rate on water-out gas well.

This data analytic approach for liquid rate estimation through machine learning contributes to the portfolio of techniques used in the oil and gas industry. It is highly applicable and replicable in oil fields with traditional and limited well monitoring data.
On-The-Fly History Matching of Simulation Models Using Generative Diffusive Learning (SimGDL)
Authors: Alnasser Mohammed H. , Maucec Marko
Published: February 2024

History matching is an inverse problem in which a geological model needs to be calibrated under uncertainty in order to produce a representative reservoir simulation model. While there are many methods for computer-assisted history matching, most of them require substantial computational power and manifest slow convergence for large-scale simulation models. To tackle these challenges, we propose a new technique for history matching reservoir simulation models using generative diffusive learning (SimGDL) [1].

Our work consisted of several steps based on conditional denoising diffusion probabilistic models. First, we generated several thousands of geologic realizations covering a wide range of spatial subsurface uncertainties. Secondly, we added various amounts of gaussian noise to these realizations and trained a U-Net to predict the added noise based on the corresponding production response. When history matching, a certain amount of noise is added to one of the geologic realizations and then the trained U-Net, guided by the targeted production response, is used to iteratively remove the noise until it converges to a newly generated, dynamically calibrated geologic realization.

To test the potential of this new approach, we created a synthetic simulation model. Several thousands of permeability realizations were prepared and used to train the diffusion U-Net. The simulation model combines a single water injector and an oil producer, where oil rate, water cut, and bottom-hole pressure were designated as production responses. Dynamically calibrated permeability realizations were generated by adding noise to some of the existing realizations and then passing them through our diffusion U-Net, conditioned by the selected target production data. The simulated dynamic responses using the generated geologic realizations showed great improvements in matching the target production data. In addition, the posterior realizations were able to retain main feature signatures from the prior distribution and the areas to be updated. Furthermore, the generated models incorporate the quantification of uncertainty, as captured with multiple geologic realizations that were used in training.

This paper presents a new method for data-driven dynamic calibration of reservoir simulation models utilizing Generative Diffusive Learning. It incorporates a robust uncertainty quantification using an ensemble of representative subsurface reservoir models. By adding further complexity to conditioning parameters, this innovative method could be further extended and scaled-up to history match simulation models with diverse structural layouts and production profiles.
Pore-Scale Mechanism of Surfactant-Polymer Flooding and the Improvements on Oil Displacement Efficiency
Authors: Chen Shaohua , Wang Jinxun , Huang Tianping , AlOtaibi Mohammed B
Published: February 2024

Many laboratory tests and field applications have successfully demonstrated that surfactant-polymer (SP) flooding is of importance and high efficiency to displace the residual oil trapped in the pores and capillaries of reservoir rock after water flooding. In this study, a micromodel experimental setup for visualized oil displacement was applied at high-temperature and high-salinity (HTHS) condition to study the synergy between a hydrophobically associating polyacrylamide (HAPAM) and different types of surfactants as mixed chemical surfactant-polymer (SP) flooding. Based on the results and captured micromodel images, the mechanisms of SP flooding to displace crude oil were investigated, and a most efficient SP flooding strategy was proposed. The physiochemical properties of the SP solutions were investigated before the micromodel displacement test. The micromodel slice was initially saturated with crude oil, followed by injections of a high-salinity water, chemical solution and subsequent water slug to displace saturated oil. During oil displacement, observed phenomena were recorded by a digital camara equipped on the micromodel device to analyze the pore-scale mechanisms of SP flooding, the viscosity alteration due to SP synergy and emulsification resulted from surfactant were also considered in the displacement mechanism. Among three surfactants, the anionic surfactant (AS) exhibited the most improved performance in oil displacement when it combined with the HAPAM comparing the other two surfactants, which is a non-ionic surfactant (NS), and a cationic surfactant (CS), respectively. The HAPAM/AS SP formulation showed a highest viscosity owning to hydrophobic association and electrostatic adsorption between HAPAM and AS comparing NS- and CS-related formulations, resulting in an enhanced sweep efficiency to displace more crude oil. Furthermore, the HAPAM/AS formulation exhibited strong emulsification to facilitate the formation of low-viscosity oil-in-water (O/W) emulsions to further enhance the flowable capacity of the crude oil, the O/W emulsion droplets can flow easily to pass through narrow throats and small or micropores by deformation along the flow, and eventually escape from the micromodel, resulting a higher displacement efficiency. Consequently, the highest production of crude oil was observed using the HAPAM/AS solution as a displacing agent comparing the other SP formulations.
Challenging Fishing Operation to Retrieve 1.68-In Wireline Tool in 6-In Horizontal Open Hole: Case Study from the UAE
Authors: Perkash W. , Alharthi R. G. , Maheshwari Y. K. , Subaihi M. H. , Franco E. , Zailani M. F. , Khan R. S. , ElAttar A. , Mostafa S. , Gul N. , Binoy A.
Published: February 2024

In the United Arab Emirates, an operation to retrieve a production logging tool that was lost-in-hole (LIH) yielded numerous insights for future operations. The fishing operation presented several challenges. First, the outside diameter (OD) 1 11/16-in. bottomhole assembly (BHA) was inside an internal diameter (ID) 6-in. open hole. The minimum completion ID was 2.635 in. The operation involved over 3,000 ft of horizontal open hole section in which the last 600 ft were facing upward.

Use of the Coiled Tubing (CT) logging equipped with a casing collar locator (CCL) played a crucial role in identifying the precise depth in the horizontal section of the production logging tool, CCL data combined with the caliper readings from a previous run helped to design the fishing BHA for retrieving the LIH tool. The designed BHA was equipped with a cutlip bell guide and an orienting tool with the aim to facilitate the latching. These datasets and challenges were considered by the intervention team in setting the most appropriate fishing strategy.

The LIH toolstring retrieval involved six runs. Initially, a conventional fishing BHA was used, but it encountered tagging issues at the gas lift mandrel (GLM). To overcome this, two straight bars were added to the fishing BHA increasing its length and avoid tagging at the GLM. During the second run, surface weight readings indicated that the LIH toolstring was being pushed along the open hole. In the third run, a similar BHA was used while pumping friction reducers. There was no evidence of the fish as the CT reached the end of the well. In the subsequent run, a lead-impression block (LIB) was deployed to detect the top of the fish. However, the LIB came without any visible marks. In the fifth run, the CT reel was replaced with an electric-cable-equipped pipe. The objective was to detect the fish in the open hole using the CCL sensor. Once the tool was identified, the engineering team modeled the fish using caliper readings and deviation survey data, enabling the proper design of the fishing BHA. The BHA was equipped with a cutlip bell guide and an orienting tool, which facilitated the latching and subsequent recovery of the tool in the following run.

With the insights gained from this operation, future operations in similar scenarios can benefit from the use of fiber optic-equipped CT. The proper interpretation of fish positioning, aided by caliper and CCL data, will allow for improved decision making in selecting the appropriate fishing tools and techniques. This, in turn, can lead to more successful and efficient retrievals of lost tools, minimizing downtime and potential operational disruptions.
Alternative Approach to Acid Stimulation in Extended Reach Multilateral Water Injector Well
Authors: Al Balushi I. A. , Charushin A. , Makawi S.
Published: February 2024

A dual-lateral water injector well was drilled in December 2022 to sustain reservoir pressure and support nearby wells production. A low injectivity of 1,500 bpd was observed from the start of the injection, which was analyzed to be due to tight dolomite formation whereas nearby wells production did not achieve the desired production rates. The objective of the paper is to describe the process of enhancing the injectivity in this extended reach dual-lateral water injector by combining several techniques.

Due to the low permeability of the well formation, a work cycle was developed to ensure the successful intervention is executed in a controlled manner. Therefore, acid stimulation treatment was conducted in two runs. Firstly, the long open hole horizontal mother-bore was accessed by means of coil tubing supported with an extend reach vibration tool and a friction reducer, where 185 stages were pumped utilizing special jetting tool. Secondly, an open-hole inflatable packer was run to isolate the stimulated mother-bore. Thirdly, the lateral was treated from the window depth via the coiled tubing/tubing annulus. Finally, inflatable packer was retrieved providing access to both laterals. The main stimulation fluid was chosen to be emulsified acid which provides retardation effect and deeper wormhole penetration.

Acid stimulation of the dual-lateral well was a complex intervention using extended reach tool along with friction reducer while selectively stimulating the second lateral using open hole inflatable packer. In the first run, CT reached 15,070 ft till lockup, while original lock-up depth without extended reach methods was expected at 13,691 ft. Total injectivity was improved in both holes whereas post-treatment pressure reduced to 2,100 psi compared to the initial injectivity test of 3,500 psi at 5 bpm. The operator concluded that the anticipated objective was exceeded by increasing the injection rate from 1,500 bpm to 2,500 bpm after bringing the well back on injection.

The paper highlights the successful acid stimulation associated with complex intervention executed through coiled tubing and proves the concept of stimulation dual-lateral well without using re-entry downhole tools to access a lateral. This case helps to present the value, challenges, lessons learned and opportunities existing in well stimulation for multilateral that would have previously been deployed through a costlier means of workover operation.
Coning Control Completion First Successful Implementation in North Kuwait
Authors: Al-Subaiei Dalal , Al-Mousawi Abdullah , Kumar Priya , Ron Angel Gonzalez , Zakrya Shamseldin , Al-Husaini Mohammad
Published: February 2024

The presence of formation water under strong water drive will support the oil production in the early life of the well then will become an issue, which is difficult to control with time. With the need of sustain and increase oil production in North Kuwait year after year, it become impassable to keep producing oil wells with low rate and rate below critical coning rate. Using Chaperone method calculation, the critical coning rate require for lower Burgan is ± 300 BLPD, to avoid coning LB well should be produce with rate less than 300 BOPD. With the high target oil rate required from NK, it is impossible to produce wells with rate below 300 BLPD.

Coning control completion (CCC) is a new technology that have been used in NK to control the coning issue in Lower Burgan, the completion contain a reverse ESP located below the oil water contact (OWC). Reverse ESP will create a counteractive pressure drawdown below the OWC to control the progression of the water cone within the oil zone. The reverse ESP will take the water below the OWC of the target zone, dump water into under-lying reservoir to minimize produced water at surface. CCC have helped NK to reduce WC from 90% to 30%.

Coning has always been an uncontrolled issue in lower Burgan, with the high pressure in LB all wells produce naturally with low WC with time coning rise-causing WC to reach 80-90%. With the increase of WC the well can't produce naturally, and it need an ESP to lift the fluid, with ESP the conning increases causing WC to increase more than 90%. CCC have helped to in reduce excessive produced water on the gathering centers and improve the Recovery Factor in partial and strong water drive Reservoirs by reducing the coning effect.

This paper will discuss the mechanism, application and the successful result of using CCC in NK and how implementing this new type of completion helped NK to improve lower Burgan reservoir.
Study on In-Situ Stress Evolution and Its Impact on Infill Well Fractures Propagation- A Case Study from China
Authors: Wang Xiaoguang. , Wu Qingxiang. , Jiang Zhibin. , Xie Dan. , Zhou Wei. , Qian Chuanchuan. , Lian Liming. , Wang Jie. , Li Zheng. , Qu Liming. , Huang Xingning.
Published: February 2024

Hydraulic fracturing of horizontal wells is an effective development mode for low-permeability reservoirs, while new drilling can enhance reservoir recovery. The drilling, fracturing, and production processes all induce changes in reservoir stress, affecting the infill wells’ fracture design. Adoption of finite element-based discontinuous discrete fracture numerical method. The extension of wellbore and fracture is described by dynamic mesh technology during drilling and fracturing, and the discontinuous discrete fracture model can be computed by using a conventional finite element mesh, which can be perfectly matched with the discrete fracture model, so as to realize the integrated numerical simulation of drilling-fracturing-production. Use the construction of infill wells in low-permeability reservoirs in Area 8 as an example, the integrated simulation of drilling-fracturing-production is carried out for the wells to be constructed in the encrypted well area, and the maximization of the exploitation economy of the well area guides the optimization of the infill wells’ fracturing. The simulation results show that the long-term production process of the old well reduces the formation pressure and ground stress in the encrypted well area, and the direction of the maximum horizontal principal stress is deflected. Considering the influence of the old well production, the drilling fluid density during the drilling of the encrypted well can no longer be designed using the original formation pressure profile. With the drilling fluid column pressure not greater than the minimum horizontal principal stress at this stage, the direction of maximum horizontal principal stress around the encrypted well is further deflected after the wellbore is drilled open, causing the initial expansion direction of the fracture to be deflected along the wellbore; injecting water to boost the pressure of the old well prior to the fracturing of the encrypted well can improve the fracturing effect of the encrypted well. The established numerical method can realize the simulation of reservoir stress evolution in the whole process of drilling-fracturing-production and the integrated numerical simulation of fracturing-production, which can optimize the design of fracturing in infill wells and improve the single-well production.
Integrated Logging While Drilling and Wireline Borehole Seismic for Safe Exploration Drilling in the Andaman Sea, Deepwater Indonesia
Authors: Sakina M. , Kelsall N. , Singh S. , Juliansyah M. N. , Jessup D. , Octaviani T , Arif F. , Permanasari D. , Halim H
Published: February 2024

A vertical exploration well, Timpan-1, was drilled in the offshore Andaman Field, deepwater Indonesia, using a unique integration of logging while drilling (LWD) and wireline borehole seismic/vertical seismic profiling (VSP) to reduce risk and increase safety while exploring the carbonate reservoir. The seismic while drilling (SWD) technology was used on the 12 ¼-in. hole section for geostopping decisions to set the 9 5/8-in. casing at the correct depth immediately above the carbonate reservoir. Once the casing reached the bottom and the drilling operation continued to well total depth (TD) on the 8 ½-in. hole section, wireline VSP was acquired to obtain the velocity profile and VSP image. The depth prediction was determined using the lookahead method, where the closer the seismic sensor, the more accurate the depth prediction. The final integrated data of both 1D images of the corridor stack from SWD and wireline VSP was displayed side by side, with overlapping levels. This aim is to have the data for the whole section and fully utilize both acquisition data. In conclusion, SWD technology is used for geostopping purposes, and wireline VSP provided the best conveyance option to help manage the depth uncertainty for the final hole section and other advanced applications of ZVSP, such as attenuation (Q) estimation. Integrating the borehole seismic acquisitions technology is the correct strategy to mitigate significant depth and velocity uncertainty risks. Thus, SWD and wireline VSP can provide a better understanding of the velocity profile and seismic interpretation of nearby Timpan-1 well.
Determination of the Connected and Isolated Porosities by a Poroelastodynamics Model
Authors: Liu Chao , Phan Dung T.
Published: February 2024

It is essential to know the connected and isolated porosities that play a crucial role in the estimation of in-situ hydrocarbon reserves of a reservoir and the determination of favorable target production regions. Yet, no effective methods are found in the literature to determine the connected and isolated porosities. In this work, we present a method to determine simultaneously both the connected and isolated porosities, using the theory of dual-porosity single-permeability poroelastodynamics. This theory is derived based on the dual-porosity dual-permeability poroelastodynamics. The dual-porosity single-permeability poroelastodynamics is associated with elastic waves propagation in fluid saturated rocks with connected and isolated porosities. Phenomena including wave dispersion and attenuation occur simultaneously due to the coupled motions of the rock matrix and fluids in pore spaces. An example is presented to demonstrate the application of the dual-porosity single-permeability poroelastodynamics in the determination of the connected and isolated porosities.
Utilization of Compact Unitized Wellhead System for Unconventional Wells
Authors: Alsaeed M. , Mukhlifi M. E. , Amer M. Al
Published: February 2024

This paper covers the introduction of a new fit for purpose design consisting of a unitized wellhead (Unihead) that has been introduced to satisfy both drilling and well stimulation requirements while optimizing the capital cost, reducing the flat time, and enhancing both rig and rig-less operations. Cost management is paramount to ensure the success for all project specifically for unconventional wells. Optimizations in casing design, drilling fluids and completion have been implemented heavily and around the globe. However, wellhead design optimization remains to be an area of improvement.

Prior to presented optimization, the existing wellhead system used in subject wells was originally designed for conventional wells. That system had two major drawbacks. First, it increased the rig flat time since it required waiting for cement to set before removing the Blow Out Preventer (BOP) to install the casing hanger. After that, the next wellhead spool is installed followed by installing the BOP. Second, the system used metal seals to isolate the annuli and also used a production tree to suspend the well after the drilling phase, which was costly.

The new system consists of utilizing a Unihead body and mandrel hangers to suspend both the production and long string casings. The annuli between the Unihead and the casing hangers are sealed by a seal assembly (Packoff) utilizing elastomer seals. After completing the drilling phase, the system will also facilitate rig-less well stimulation operations. Furthermore, the system will enable the installation of downhole completion and a velocity string after well stimulation. Finally, the well will be produced through the velocity production tree.

The new system was successfully installed with outstanding results and offered several advantages. This includes the time optimization, capital cost reduction and significantly reduced flat time. The system achieved these benefits through the proper system design that is fit for purpose for both rig and rig-less operations and eliminated the challenges usually encountered with conventional system design.
Achieving Ultimate Production Recovery by Building on the Successful Development Through Infill Project Utilizing Fit for Purpose Integrated Static and Dynamic Modelling
Authors: Shoaibi S. S. Al , Omairi S. , Riyami H. Al , Suleimani A. Al , Barwani A. , Hajri Y. , Khaduri S. Al
Published: February 2024

Objective/Scope

This paper discusses the approach utilized to model the static and dynamic data of a field in order to come up with a development plan for infill wells. These models are required to estimate the remaining in place hydrocarbons in analytical approach that is fit-for-purpose to cater for the project value drivers as well as the decisions required to be taken.

Methods/Procedures/Process

The field went through development plan by drilling oil producers as well as water injection wells. All FDP wells have been drilled already. Next development phase for the field is to drill infill wells and change the concept from 200m PPI spacing wells to a finer infill spacing well.

A study was conducted aiming to mature the volumes associated from appraising stage to commercially developed phase through Full infill development for the field.

Results/Observations/Conclusions

Due to presence of multi analogue fields which are producing in similar manners, it was proposed to use these analogues to come with the study plan for the field which resulted in putting fit for purpose plan to mature the volumes by not compromising the value drivers. In addition, the key decisions for the project are answered through this integrated plan. Furthermore, early development wells are planned to be executed at earlier stage to calibrate model result.

Novel/Additive info

This paper summarizes the approach utilized in the study which include developing static maps from Equivalent Oil Column data (EOC) using petrophysical properties from log data gathered in existing wells and use these maps to initiate dynamic box models that are used to history match existing producers and subsequently forecast the production in the proposed well location for infill purposes.
Uncertainty Quantification and Management in Model Calibration and History Matching with Ensemble Kalman Methods
Authors: Al-Turki A. A. , Hammad K. J. , Sudirman S. B. , Sawlan Z. N.
Published: February 2024

History matching field performance is a time-consuming, complex and ill-posed inverse problem that yields multiple plausible solutions. This is due to the inherent uncertainty associated with geological and flow modeling. The history matching must be performed diligently with the ultimate objective of availing reliable prediction tools for managing the oil and gas assets. Our work capitalizes on the latest development in ensemble Kalman techniques, namely, the Ensemble Kalman Filter (EnKF) and Ensemble Smoother (ES) to properly quantify and manage reservoir models’ uncertainty throughout the process of calibration and history matching.

Iterative ensemble algorithms have been developed to overcome the shortcomings of the existing methods such as the lack of data assimilation capabilities and abilities to quantify and manage uncertainties, in addition to the huge number of simulations runs required to complete a study. In this work, NORNE benchmark model was used to generate an initial ensemble of 40 to 50 equally probable reservoir models was generated with variable areal, vertical permeability and porosity. The initial ensemble captured the most influencing reservoir properties, which will be propagated and honored by the subsequent ensemble iterations. Data misfits between the field historical data and simulation data are calculated for each of the realizations of reservoir models to quantify the impact of reservoir uncertainty, and to perform the necessary changes on horizontal, vertical permeability and porosity values for the next iteration. Each generation of the optimization process reduces the data misfit compared to the previous iteration. The process continues until a satisfactory field level and well level history match is reached or when there is no more improvement.

The application of the Iterative ensemble algorithms is demonstrated by history matching NORNE benchmark model. Multiple iterative ensemble smoothers with adaptive inflation and localization techniques were implemented and compared. The ES algorithms preserved key geological features of the reservoir model throughout the history matching process. During this study, ES served as a bridge between classical control theory solutions and Bayesian probabilistic solutions of sequential inverse problems. The methods demonstrated good tracking qualities while giving some estimate of uncertainty as well.

The updated reservoir properties (horizontal, vertical permeability and porosity values) are conditioned throughout the ES iterations (cycles), maintaining consistency with the initial geological understanding. The workflow resulted in enhanced history match quality in shorter turnaround time with much fewer simulation runs than the traditional genetic or evolutionary algorithms. The geological realism of the model is retained for robust prediction and development planning.
Assessment of Thermal Maturity Trends in a Lower Paleozoic Source Rock Formation
Authors: Alraddadi Abdullah , Karg Harald , Salem Ahmed , Alfraih Ibrahim
Published: February 2024

The Arabian plate has been known by its west-east asymmetric lithospheric structure, expressing itself in distinct topography and geological patterns. The western portion of the plate, consists of the Arabian Shield, exhibiting buoyant and exposed basement, while the eastern portion belongs to the wider Western Gulf Basin (Fig. 1), hosting a variety of Phanerozoic basins, which were subjected to continuous subsidence and deep burial since the Late Proterozoic terrane amalgamation. This pronounced asymmetric surface geologic pattern has deep-seated thermal and physical drivers (Stern and Johnson, 2010), governing basal heat flow and heat distribution within the sedimentary column, which ultimately drives the thermal maturity pattern of the Lower Paleozoic Source Rock across the region.

The main goal of this study is to highlight observed trends of the thermal maturity of Lower Paleozoic Source Rocks, and to discuss the primary causes for these trends within a smaller section of the Western Gulf Basin (Fig. 1). Burial history and heat flow modeling were utilized in this study based on temperature and pyrolysis data collected from around 37 wells across the study area of approximately 23,000 km2.
Sustainable Redevelopment of the Volve Field Amidst Recent Energy Security Challenges Faced by Northwestern Europe; A Case Study from Central North Sea
Authors: Ahmad M. Nauroz , Yaser M. , Abdel-Basset M. , Abdelrahim R. , Siddique E. , Abdelbagi M. E. , Firmansyah B. , Aktar M.
Published: February 2024

This study outlines the brownfield development plan that was employed for the Volve oil field in the central North Sea. The Volve field had been abandoned in 2016 due to economic reasons. Data from the Equinor Volve field repository was analyzed with a focus on the Hugin sandstone reservoir of Mid-Jurassic age. The goal was to identify the most suitable techno-economic approach to extend the life of the asset while also being environmentally sustainable.

The study was framed around a comprehensive geological, petrophysical, reservoir and production engineering evaluation that served as a basis for a detailed economic evaluation for the asset. The resulting dynamic reservoir model included a thorough history matching of the wells’ and field's production behavior to identify the remaining sweet spots. Two field development options were evaluated driven by critical economic variants such as Net Present Value, Internal Rate of Return, and Payout Period, using the UK Royalty/Tax fiscal regime as the framework for calculating cash flow. Methods to achieve a low carbon footprint were also incorporated.

The first option, a double peripheral layout spot pattern with six producers and two injectors, achieved the highest incremental production growth. However, due to its significant environmental impact, it was deemed unsuitable. Based on the economic evaluation, the optimal scenario for the redevelopment of Volve field was six producers, two water injectors and one water source well. The base development plan included latest development in drilling technologies such as Managed Pressure Drilling (MPD), advanced Inflow Control Device (ICD) completions for producers as well as regulating water injection through WFR's and digital end-to-end solutions. All considered scenarios were evaluated for their carbon footprint, and sustainable technologies were considered in the final plan for seeking approval from governing regulatory authorities.

The Volve field re-development plan has been achieved through deployment of novel techniques to smartly drill and complete wells to achieve sustainable incremental reserves. The redevelopment of Volve field is considered critical in the current energy demand and security challenges faced by Northwestern Europe and aims to open several other assets which have been considered non-viable during the last downturn.
Wellsite Carbon Reduction with Improved Engine Load and Count Management
Authors: Auld S. , Kern S.
Published: February 2024

The energy industry's focus on Greenhouse Gas (GHG) emissions reduction requires solutions that are both cost effective and scalable across a global rig fleet (specific to a rig contractor) to reduce excess fuel and associated GHG emissions. A system was designed and implemented using existing assets without requiring complete refurbishment, to provide sustainable benefits, focused on the foundational concept of excess engine hour reduction.

One method to reduce drilling emissions is by reducing fuel consumption: specifically, by reducing excess engine hours for rig activities. Excess engine hours are defined as the measured time when more engines are running than necessary to supply a given load. Using engine load threshold data for optimal engine use is a universal solution to provide GHG emissions reduction in an efficient manner, not dependent on a rig type or specification. An engine management-based solution is efficient, removing the time-intensive task of isolating variables associated with a given rig activity.

Clear results were seen in both micro and macro studies by reducing underloaded engines throughout the well cycle. In a two-well comparison, focusing on excess engine hour reduction through engine management alone, the efficiency gains from Well 1 to Well 2 were 902 gallons of diesel and 9.2 tons of CO2e. Annualized, this is an equivalent 16,500 gallons of diesel and 181 tons of CO2e per rig. In a larger study, the primary goal was to decrease the amount of engine time in an underloaded state across the fleet to an under 30% target. Prior to program launch, 25% of the rig fleet regularly achieved the below-30% target. Roughly one year after launch, 48% of the rig fleet regularly achieved the below-30% target, nearly doubling initial metrics. Annualizing the benefits from pre-launch to post-launch with a rig fleet growth of 48% between the two analyses, an excess engine hour reduction of 166,744 hours was achieved, having a direct impact on fuel and GHG emissions reduction. The solution is now successfully deployed on a fleet of 98 rigs.

The improved baseline performance achieved with engine management as demonstrated in this example will allow for proper evaluation of additional technologies and drive fit-for-purpose solutions that solve for the outcome needs of the industry when grid or highline power is not readily or consistently available.
Bridging the Gap: A Pathway to Robust Rock Strength Modeling and Reliable Sand Production Risk Assessment in Thermal Steam Project
Authors: Riyami H. Al , Syabi M. Al , Zadjali R. Al
Published: February 2024

Thermal steam project has been successfully implemented in Haradh formation in A-East field in the south of the Sultanate of Oman. This project was developed outside the crest and expanded further to the north. Sand production control was identified as a potential risk; therefore, a sand prediction model was required to assess the rock strength at both hot and cold operating production conditions. Due to the large uncertainty in rock strength for Haradh at high temperatures, a dedicated fit-for-purpose geomechanics program was executed for an appraisal well drilled in the field. The main objective was to determine the strength characteristics of Haradh at room and elevated temperatures, which would help to assess the reservoirs stability during the thermal steam injection process. This paper outlines (i) the results of Geomechanical laboratory analysis, (ii) elastic and physical properties from log data and (iii) generated log-derived rock strength model.

Large rock volume XL-Rock Rotary Sidewall (SWC) coring was carried out in X-well across the full depth range of Haradh oil column. The Computerized Tomographic scanning images were used for quality control and selection of the best core plugs for testing. Unconfined compressive strength (UCS) tests were performed at atmospheric confining stress (confining pressure is zero) and "as received" condition at room (20-25 °C) and elevated (200 °C) temperatures to simulate the operation conditions during steam injection. Thin section petrographic and point counting analysis was conducted to study the impact of mineral contact on the UCS. Empirical relationships were established between core measured UCS and log data to develop UCS profile across Haradh formation.

UCS results show medium rock strength ~ 13 −17 MPa of Haradh sandstone at room temperature. As the test was performed at high temperatures, the UCS value shows a drastic drop in the rock strength of more than 50% reduction (range between 3.16 to 6.84) which might indicate a potential risk of rock failure at high temperatures. The comparison between the laboratory measured UCS and the profiles obtained from the empirical models show a reasonable match specially with the Petroleum Development Oman (PDO) correlation. The study results show that Haradh rock's strength may decrease during thermal steaming operation, which could potentially lead to reservoir instability and failure. A more detailed evaluation is recommended to assess this risk and investigate the impact of temperature induced stresses on sand production using FIST (Fully Integrated sand prediction tool) rock failure model.
When Machine Learning Helps to Understand a Facies Controlled Two Ways Tilted Contact in a Large Carbonate Reservoir
Authors: Robail Frederic , Sanyal Satyashis , Gazali Ismail Marzuki , Azudin Ahmad Nazmi B. M. Noor , Tabatabai Seyed Mehdi , Wulandar Ratih , Lubis Zulfikar
Published: February 2024

This case study presents an example of a large multibillion barrels in place carbonate reservoir where a two way tilted contact has been identified. Based on petrophysical analysis integrated with sedimentology studies and structural analysis, a tilted contact with two perpendicular directions (North-West / South-East and South-West / North-East) has been identified in this large structure. The mapped contact surface was found to be near parallel to the top depth structure, while the oil column thickness remained generally consistent throughout the field.

During a recent drilling campaign, new cores have been cut in several wells. These cores cover the entire reservoir section from reservoir top to reservoir base, as well as across the depths of the measured resistivity-based contacts. Thus, a complete sedimentological core description as well as routine core analysis and special core analysis are available both in the hydrocarbon and water legs.

Machine learning algorithms have been used here for two purposes. Firstly, using core plug permeability measurements to create a core based permeability model and then to propagate it throughout the field to the uncored wells. Secondly, using sedimentological core descriptions, a depofacies and a lithofabrics frameworks have been established and propagate to the entire field. This approach has been validated by means of production logs and correlation panels.

A good correlation between the permeability profile, the facies distribution and the resistivity-based oil water contact (OWC) location has been observed. This suggest that the reservoir facies control the two-way tilted contact in this reservoir. Additionally, based on the regional tectonic’ setting of the area, a structural tilt is envisaged to have been active in geological time. This has likely contributed to a certain extend to this two-way tilted contact.

The tilted contact orientation in two perpendicular directions identification has helped in sensitizing the hydrocarbon in-place and recoverable volumetric impact to support the present and future field development plan and the long-term sustainable production of this reservoir.
Reservoir Quality Prediction: MICP-Derived Microporosity Effects on Sonic Velocity
Authors: Baechle G. , Alkaba F. , Tudares N. Q. , Hursan G.
Published: February 2024

This study uses a sufficient number of core plugs with the objective to combine mercury injection pressure data for pore characterization with conceptional pore type models using sonic velocity. The plugs are analyzed to establish relationships between porosity, pore structure, permeability and log-derived sonic velocity. This paper combines two well-established methods for reservoir quality prediction: pore typing using sonic velocity and pore throat characterization using mercury injection capillary pressure (MICP) data.

Microporosity is known to be a significant parameter for permeability prediction. In our dataset microporosity relates to velocity at a given porosity. MICP derived pore throat parameters are linked to microporosity and to sonic velocity. Linking MICP derived petrophysical rock types through microporosity with poroelastic properties opens the potential to predict reservoir quality using sonic data at the log scale. Classifying MICP data by means of fraction of microporosity provides a geologically meaningful classification and interpretation of rock properties.
Quantifying the Influence of H2S Impurities on CO2 Storage Efficiency in Carbonate Reservoirs: An Experimental Findings
Authors: Razak A. A. A. , Saaid I. M. , Yusof M, A, M. , Zaidin M. F. , Zulkarnain N. N. , Amir M. I. M. , Sazali Y. A. , Habarudin M. F.
Published: February 2024

This study investigates the implications of Hydrogen Sulphide (H2S) impurities on Carbon Capture, Utilization, and Storage (CCUS) operations in carbonate reservoirs, with a specific focus on Field X in offshore Malaysia. The research examines the interaction between Carbon Dioxide (CO2) and H2S under reservoir conditions, aiming to better understand their impact on reservoir formation and geochemical interactions. The goal is to gain insights into storage design and predictive capabilities when dealing with impurities. Advanced analytical techniques, including ICP, RCA, XRD, and SEM-EDX, were used to analyze the mineral composition and physical characteristics of core samples from Field X. Experimental tests involved exposing these samples to CO2 with H2S dissolved in brine and aging them under reservoir conditions. The research findings indicate that the presence of H2S in CO2-dissolved brine leads to a reduced rate of dissolution of carbonate rock samples, potentially offering benefits for CCUS storage. These insights into CO2-H2S interactions in carbonate reservoirs can be valuable for optimizing CCUS storage strategies, ensuring long-term stability and security, particularly in offshore Malaysia.
Prediction of Pure Mineral-H2-Brine Wettability Using Data-Driven Machine Learning Modeling: Implications for H2 Geo-Storage
Authors: Ali Muhammad , Tariq Zeeshan , Mubashir Muhammad , Kamal Muhammad Shahzad , Yan Bicheng , Hoteit Hussein
Published: February 2024

Greenhouse gases, particularly carbon dioxide (CO2), have the effect of raising the Earth's temperature. To combat this issue and reduce carbon emissions, it is advisable to shift towards the widespread utilization of cleaner fuels, such as hydrogen. The establishment of a global-scale hydrogen economy, coupled with hydrogen geological storage, presents a viable solution to meet the world's energy demands while accommodating peak usage periods. In geological hydrogen (H2) storage, the rock formation wetting characteristics are essential to regulate fluid dynamics, injection rates, the spread of gas within the rock matrix, and safety considerations. The wetting characteristics of minerals within the rock are significantly influenced by geological factors. To assess the wetting behavior of a mineral/H2/brine system under geo-storage conditions, innovative approaches have emerged. This research utilized a combination of advanced machine learning models, such as fully connected neural networks, adaptive gradient boosting, random forests, decision trees, and extreme gradient boosting to forecast the wettability characteristics of a ternary system comprising hydrogen (H2), brine, and specific rock minerals (namely quartz and mica). The predictions were made under various conditions, including different pressures ranging from 0 to 25 MPa, temperatures spanning from 308 to 343 K, and salinities of 10 wt.% NaCl solution. The machine learning models demonstrated remarkable accuracy in predicting mineral/H2/brine system's wettability (contact angles, advancing and receding). Incorporation of various experimental values have established correlations based on ML techniques. The performance and reliability of these models were rigorously assessed using statistical methods and graphical analyses. The deployed ML models consistently provided accurate predictions of wettability across diverse operational scenarios. Notably, the suggested model exhibited a root mean square error (RMSE) of 0.214 during training and 0.810 during testing. Furthermore, sensitivity analysis revealed that pressure exerted the most significant influence on mineral/H2/brine system's wettability. These ML model outcomes can be effectively utilized to anticipate hydrogen geological storage capacities and ensure the security of restraint in large-scale developments.
An Evaluation of Imaging-While-Drilling Technologies: A Comparative Study of Functionality, Applications, and Performance of Different Sensors
Authors: Manuaba Ida Bagus Gede Hermawan , AlHassan Mohammed , Taher Ahmed , Najrani Hussain
Published: February 2024

Most logging-while-drilling (LWD) measurements can resolve azimuthal changes around the wellbore and create borehole images, which are useful for well placement, formation evaluation, drilling operations, and production. The resolution of the images varies depending on multiple aspects of the sensor design such as vertical resolution, acquisition rate, and the number of azimuthal sectors acquired. High-resolution images are utilized for reservoir characterization, fracture identification, and sedimentological research, whilst lower-resolution borehole images are employed for well placement and geomechanics.

Multiple imaging sensors, including gamma ray, ultrasonic, micro-resistivity, and two different designs of density tool, were deployed in the same drilling bottom-hole assembly (BHA). The two density tools had different azimuthal resolutions (16 and 32 sectors), while the micro-resistivity sensor provided two different image resolutions, generating 1-in. and 0.4-in. resolution images with multiple detectors. More than 250 sectors, with a resolution of less than 0.2 in., were recorded by the ultrasonic imaging sensor.

Data was acquired in multiple runs with the same BHA configuration, providing insight into time lapse analysis, wellbore deterioration with time, and fracture propagation after pumping acid into the wellbore following a stuck occurrence.

The evaluation of multiple images acquired in different runs provided a valuable insight into the different sensors’ advantages and limitations. This study can be used as a comprehensive guide for the evaluation of LWD imaging tools.