bluuebunny/crossref_metadata_2025 huggingface dataset:
Which is the Most Attractive IOR Method to Produce the Venezuelan Highly Viscous Oil Resources in the Energy Transition Era? A Comprehensive Review of Research and Field Applications
Authors: Rodriguez Fernancelys , Delamaide Eric , Rousseau David , Bekri Samir
Published: October 2022

Venezuela has been a potential producer of highly viscous crude oils for more than a century, thanks to its large resources located at the Lake Maracaibo and Eastern Venezuela basins in the Orinoco Oil Belt. Despite these huge resources, Venezuelan oil production is going through one of the greatest crises in its history, presenting a dramatic production decline, for which the application of Improved Oil Recovery (IOR) methods with low environmental impact (low carbon emissions, low water consumption, etc.) is crucial to increase oil production.

The main methods applied in Venezuelan highly viscous oil reservoirs (heavy, extra-heavy and bituminous oil reservoirs) have been cold production with sand by vertical and horizontal wells with artificial lift pumps, waterflooding, thermal IOR/EOR methods (steam drive-based methods), chemical EOR (CEOR) methods, namely polymer and surfactant-polymer (SP) flooding, hybrid methods (e.g. thermal combined with solvents or CEOR methods), among others.

Research works in CEOR methods for Venezuelan highly viscous oil reservoirs have shown that high oil recoveries may be possible for oils with viscosities up to 13,400 mPa.s. On the other hand, for the case of bituminous oil reservoirs (e.g. viscosities up to 50,000 mPa.s) thermal IOR methods and combinations with chemicals, nanoparticles, or solvents may increase oil production significantly. The methods reviewed in this article are: waterflooding, chemical flooding (e.g. polymer, surfactant, alkali and a combination of them), steam drive methods (e.g. CSS, In-situ Combustion and SAGD), solvent flooding, microorganisms and hybrid methods.

Based on research and field tests, CEOR methods may lead to increased oil recovery of extra-heavy oils with low carbon emissions compared to thermal EOR methods, thus making SP flooding and low salinity polymer flooding among the most attractive technologies. Depending on the type of chemicals evaluated, recovery mechanisms such as mobility control, IFT reduction, ion exchanges and/or wettability alteration might be most efficient. It also appears that hybrid methods have achieved the highest recovery at the laboratory scale (e.g. In Situ Combustion with nanoparticles). For the medium-heavy oil reservoirs of the Maracaibo Lake Basin, waterflooding combined with infill well optimization and microorganism flooding are encouraging IOR methods with low environmental impact. The greatest challenges in the application of these technologies are related to technical and economic considerations that will be decisive for the implementation of the IOR processes at the pilot scale and/or massification at the field scale aiming to increase Venezuelan oil production in this era of the energy transition.
Reservoir Performance Analysis of Eighty-Four Years of Immiscible Gas Injection in a Matured Carbonate Reservoir, Bahrain Field
Authors: Hameed Mohamed , Konwar Lakshi , Alanaisi Isa , Ali Waleed , Alawainati Ebrahim
Published: October 2022

The Bahrain Oil Field ("Bahrain Field"), wherein the first oil discovery was made in the Gulf region in 1932, is now in a mature stage of development. Mauddud is the major oil-producing reservoir in the Bahrain Field, situated in an anticlinal feature of the middle cretaceous period. This is a highly undersaturated, low-dip, layered, heavily faulted, and preferentially oil-wet reservoir. Crestal gas injection (GI) in Mauddud has continued to be the dominant drive mechanism since 1938, making it the first improved recovery project in the Arabian Gulf region. This paper summarizes the performance of nearly 84 years of gas injection in Mauddud reservoir.

Performance-based analysis is carried out using different analytical techniques to determine voidage replacement and maximum gas-cap expansion rate to avoid gas overrunning and injection requirements. Volumetric sweep is estimated using volume of gas injected and gas cycled. Recovery is calculated based on material balance analysis using hydrocarbon pore volume (HCPV), gas injected, free gas-cap volume, and volume of residual oil in gas-cap (VOR). Semilog analysis of free gas/oil ratio (GOR) versus cumulative oil (Np) yields swept pore volume and moveable oil in different areas. Gas management strategy is devised based on wells to be shut-in, cut-off GOR, oil deferred, gas cycling limit, and remediation of high GOR wells with gas shut-off workovers. Optimum number of infill wells is evaluated based on NPV (net present value) for both vertical and horizontal completion.

Gas injection gravity drainage is an efficient mechanism in the Mauddud reservoir. Based on gas expansion rate to avoid gas overrunning, maximum GI rate is 652 MMscf/D. The volumetric sweep by gas is around 80%, giving a 50% recovery in gas-invaded areas. Critical gravity drainage oil rate per well is 383 STB/D. The average cycling of gas was 60% initially during 1970's, declined to 50% during 1986 to 2000, and currently increased to over 80%. The cumulative gas cycling is around 70%. Areas B, D, G, and H have the highest remaining mobile oil and should be the focus for infill drilling. A GOR cut-off of 80,000 scf/STB involves 97 wells, resulting in a gas reduction of 200 MMscf/D and an oil rate of 1,600 STB/D. A curtailment of free gas production of 100 MMscf/D will reduce the gas cycling from 87% to 70%. Cased hole horizontal well trial is promising based on workovers of open-hole horizontal well and newly drilled horizontal well trial with cemented liner. The development of Mauddud with a mix of both deviated/vertical and horizontal wells will reduce the number of wells in the tight spacing drilling campaign and provide robust economics. The methodology and analytical techniques described in this paper can be used for performance-based analysis of a large immiscible gas injection project.
An Ensemble-Based Infill Well Location Solution: A Cloud Native Application for Automating Well Placement and Evaluation
Authors: Pongtepupathum Wanida , Lang Philipp , Adeyemi Tobi
Published: October 2022

Field development planning moves from using deterministically constructed reservoir models to stochastically generated ensembles of models to better capture subsurface uncertainties. This leads to a challenge on how to understand reservoir dynamics and extract insights because of the large volumes of data involved. The objective of the presented system is to demonstrate how cloud-based computing can help to derive actionable insights of this large volume of data through automation, machine learning, and elastic scaling.

In this paper we present a cloud-native solution for optimizing and evaluating ensemble-based infill well locations. An opportunity index (OI) is derived from static and dynamic grid properties of reservoir simulation and a connected component search for every realization. Probability maps of OI are constructed to present the likelihood of high-OI areas from all simulations to propose infill well targets for the ensemble. Infill wells are automatically evaluated and ranked by ensemble field production increases. The workflow is deployed in a cloud-based system to leverage elastic scaling of compute resources to cope with the large volumes of data inherent in ensemble models.

The result from deploying this new workflow in a mature field in the North Sea shows that optimization of infill well targets at the ensemble level increases the robustness of targets compared to the alternative of selecting one or a few realizations. When randomly selecting two deterministic cases to analyze infill well locations, we observe inconsistency in candidate well locations. In case A, little opportunity is shown in the northern part of the reservoir and no opportunity in the southwestern part, whereas the result from case B shows almost the opposite, having a large area of opportunity in the northern part and a small opportunity in the southwestern part. By applying the proposed solution, only focused areas of the northern part of the reservoir are suitable for candidate well locations. The study time of target identification and evaluation is significantly shortened. The cloud-based deployment removes the company's need to own and manage powerful computer and data-storage infrastructure. In summary, the solution improves the workflow efficiency and provides high-quality results for field development decision making.
Lessons Learned from Implementing Smart Liners for Improved Matrix-Acid Stimulation of Carbonate Reservoirs
Authors: Mogensen Kristian , Al Hosani Fahad
Published: October 2022

Smart Liners are based on the limited-entry liner principle, which consist of an uneven spacing of a limited number of small holes drilled through the liner to mechanically divert acid along the entire reservoir drain. Past deployments have concentrated on extended-reach wells for which no other efficient matrix-acid stimulation techniques exist. With more than 100 deployments last year, ADNOC has significantly expanded the operational envelope in terms of pump rate, hole size, and well length.

Results from the Smart Liner implementation have been very encouraging so far. The general observation is that long-term productivity or injectivity is doubled, sometimes tripled, and the entire wellbore contributes to flow, documented by pre- and post-stimulation production logging. The technique has been successfully applied to several oil producers and water injectors, as well as to one gas producer, and yields superior well performance also in situations where conventional techniques can be deployed.

A number of points are worth highlighting: The technique is well-suited for both short and extended-reach wells; however, hole spacing designs strongly depend on the well lengthThe technique works for carbonate rocks of different lithology, such as limestone and dolomite (in addition to numerous chalk applications documented in the literature)Heterogeneity can to some extent be mitigated by appropriate placement of swellable packers and adjustment of hole density prior to stimulationThe high jet velocity through the small holes provides the right initial conditions for wormhole propagationFor water injectors, a pre-stimulation baseline injection period that cools the near-wellbore region in high-temperature reservoirs may improve the wormhole propagation.

The rapid deployment of this technique as well as the scale of implementation is unique in the industry.
Enhancing CO2 Foam Viscosity and Stability at Harsh Reservoir Conditions Through the Synergetic Interactions of Surfactant and Polymer
Authors: Al-Darweesh Jawad , Aljawad Murtada Saleh , Kamal Muhammad Shahzad , Al-Yousef Zuhair , Mahmoud Mohamed
Published: October 2022

The injection of foam into petroleum reservoirs has attracted special interest in the last decades. Some applications include; fracturing, stimulation, and gas mobility control during gas EOR processes. Utilizing foam in well stimulation is promising as it consumes less water than water-based fracturing fluid, is less damaging to the formation, and provides an effective proppant carrying capacity and transportation. This paper studies the synergic effects of surfactant-polymer system on the rheology and stability of foamed acid at high temperature.

A modified high-pressure, high-temperature (HPHT) foam rheometer was utilized to measure the apparent viscosity of CO2-foamed acid at 1,000 psi and 120 ℃. Additionally, a novel HPHT foam analyzer was used to characterize the following parameters; foamability, foam stability, foam structure, bubble count, and size under the same conditions. HPHT foam analyzer allows detecting the height and structure of foam all together as a function of the foam decay. Surfactant screening showed that Armovis is thermally stable at high temperatures and therefore was used in this work.

Results showed that the polymer enhanced the foamed fluid viscosity significantly. The apparent foam viscosity increased by 43 %, once 0.5 wt% of superpusher polymer was synergic with 1 % Armovis-surfactant. The results of the HPHT foam analyzer indicated that the Armovis/polymer system is thermally stable and capable of resisting high salinity. The foam half-life improved by 12 times when 0.5 wt% of the polymer was added. Also, the bubble growth rate reduced remarkably, this improvement was due to the adsorption of surfactant and polymer molecules at the gas/liquid interface, which resulted in the reduction of gas permeability through the liquid film.

This study investigates the synergy of polymer (superpusher SAV 522) and foamer (Armovis) in enhancing CO2 foam viscosity and stability at high pressure, temperature, and salinity. Furthermore, the surfactant-polymer systems evaluated can be investigated and used as stimulation fluid systems at temperatures up to 120 °C.
A Laboratory Study to Develop Co2-Foam Formulation for High Temperature and High Salinity Carbonates Reservoirs in Abu Dhabi
Authors: Guillon Valentin François , Gland Nicolas , Odier Celeste , Delamaide Eric , Almesmari Ali Hassan , AlSumaiti Ali M. , Masalmeh Shehadeh K.
Published: October 2022

Specifics challenges for chemical enhanced oil recovery (cEOR) exists in high temperature and high salinity carbonate reservoirs in Abu Dhabi especially with intermediate to high permeability range (10 – 100s mD). CO2-Foam process was investigated through a careful laboratory approach. This involves extensive laboratory work including coreflood experiments to select the most effective process in terms of foam characteristics and behavior.

Foam formulations in various brine (sea water, formation brine) were selected based on a workflow relying on bulk measurements such as solubility, stability, foam properties with/without oil, and solubility robustness versus brine and temperature variations. Sandpack tests were conducted to characterize the foam rheological behavior of various formulations at various gas fraction.

A formulation based on formation brine was then selected. Coreflood on restored reservoir cores were conducted to fully characterize its behavior toward interstitial velocity and gas fraction variation in porous media without crude oil. CO2 foam behavior in reservoir core was finally investigated in presence of oil.

The selected CO2 foam shows promising foaming behavior for such harsh conditions. It exhibits a usual shear-thinning behavior in porous media showing promising mobility reduction factor (MRF) at in-depth interstitial velocity. Critical shear-rate was observed in sandpack experiments.

High quality foam forms only for higher velocity and is maintained when velocity is decreased. This critical interstitial velocity in 40 mD reservoir cores is very low (below 0.3 ft/day) whereas it is above 20 ft/day in the higher permeability sandpack. The behavior toward gas fraction shows a stable MRF from 0.5 to 0.8-0.9 with a critical Fg between 0.8 and 0.9.

Foam behavior in presence of oil was evaluated in reservoir cores. Though foam quality is significantly impacted by oil, foam was found to form. Comparison of alternate injection and co-injection shows the necessity to fine tune slug sizes in case of an alternate injection to ensure a lasting foam.

A significant selective mobility reduction (SMR) was observed when moving from high permeability sandpack to intermediate permeability reservoir cores. CO2-Foam mobility reduction increases by an order of magnitude with the permeability, showing higher MRF in high permeability.

This applied laboratory study on intermediate permeability, high temperature, and high salinity carbonate core sample shows that a foaming formulation was found in such challenging conditions. This formulation in formation brine was proved to develop foam at low shear-rate with low MRF at reservoir conditions in reservoir cores and a high MRF in high permeability sandpack. More work is still needed to increase the resistance to oil and evaluate the SMR effect in reservoir cores.
Gas Kick Well Control Situation in High-Temperature Well Managed with Oil-Based Mud and Managed Pressure Drilling Technology
Authors: Spagnolo Salvatore , Giubertoni Matteo , De Bonis Emanuele , Cavagnero Giovanni , Sirugo Arianna
Published: October 2022

A gas kick in high-temperature well drilled with oil-based mud represents a significant challenge, as the understanding of physical and chemical interactions play a substantial role in the interpretation and decision-making processes.

This work provides theoretical and physical explanations for the multiple phenomena observed during an actual well control event, and their impact on the interpretation of the well behavior. Moreover, this paper provides useful insights on the additional capabilities offered by the usage of the Managed Pressure Drilling (MPD) technology in managing a gas kick.

A peculiar well control situation occurred in a MENA exploratory well while drilling the 12 1/4" x 13 1/2" section. The particular wellbore features such as high-temperature conditions, gas bearing reservoir layers and oil-based mud, all contributed to make the management of the dry gas influx more challenging and difficult to interpret.

Several procedures were needed to regain the control of the well, that was complicated by the effects of oil-based mud thermal expansion, gas solubility and diffusivity principles. Managed Pressure Drilling System (MPD) was also deployed to manage the influx, with a non-conventional dynamic pore pressure evaluation performed during the well control situation.

The uncommon conditions in which the kick occurred, made the interpretation of the well data particularly challenging. The paper will present a detailed engineering analysis and data interpretation required to manage in a safe and efficient manner a gas kick during well construction operation via the understanding of the interaction between multiple phenomena like gas migration, oil-based fluid thermal expansion and oil compressibility, gas diffusivity and solubility. In the presented application, MPD technique is displayed as an added value useful to better understand the well behavior and drive the decision of the required kill mud weight needed to regain control of the well.

Since geological uncertainties are likely in an exploratory context, and high temperature conditions with oil-based mud may exacerbate the risk of a kick due to the Equivalent Static Density (ESD) reduction caused by thermal expansion, the paper will provide the tools and principles needed for a thorough understanding of the wellbore behavior in similar situations.
Successful Implementation of Nanoparticle Deformable Sealing Polymer to Eliminate Differential Sticking of Zeit Sand- A Case Study from Gulf of Suez
Authors: Eissa Amr , Mamdouh Ahmed , Abdelrazik Mohamed , Abdel Maksoud Ashraf , Ouda Abdallah , Hamdy Ahmed , Farouk Mohamed , Ibrahim Lotfi , Salama Ayman , Saber Ragab
Published: October 2022

This paper will describe a successful application of Nano deformable sealing polymer to mitigate a high risk of differential sticking while drilling weak sand of Zeit formation with 17.2 ppg mud weight with overbalance up to 2,500 psi. While trying to combine Zeit and S.G formation with 17.2 ppg mud weight. Two cases in offsets had differential sticking that resulted in well re-spud and isolate Zeit formation by casing string. In the subjected well, it was deeper, so it was impossible to sacrifice casing string to mitigate differential sticking. Application of Nano deformable sealing polymer to decrease the pore pressure transmission by filling the interspaces between bridging material and greatly improve the quality of the filter cake to be thin and impermeable. In addition to drilling fluid enhancement, the condition of the differential sticking was analyzed and improvement in the BHA contact area, BOP stack configuration, and well profile. In this paper engineering principles, laboratory tests of chemicals and actual field results of these improvements will be presented.

It was the first time to use Nanoparticles in the Gulf of Suez, extensive laboratory tests and simulation modeling was performed to formulate the right bridging material and Nanoparticles concentration that fit the characteristics of Zeit sand. The bridging material was decreased from a commonly used value in the field of 50 lb/bbl to 20 lb/bbl to decrease the filter cake's thickness while achieving an HTHP value of less than 2 ml/30 min and spurt loss of zero. PPA test was performed daily during the execution phase that reflected the optimum quality of the actual sample filter cake and also matches the laboratory test performed in the planning stage. In case of a well control event, the BOP stack was supported by a back annular to continue reciprocation of the drilling string while repairing the main annular element if failed. BHA contact area was decreased by optimizing the directional plan to keep a low angle across Zeit sand and by minimizing BHA’s un-stabilized length.17-1/2" hole was drilled successfully using 17.2 ppg mud weight without any issue relating to differential sticking even after losses experienced in Zeit sand.

Due to the successful application of Nano deformable sealing polymer and engineering approaches, it was the first time in GOS to drill Zeit sand with mud weight of 17.2 ppg successfully saving one section in the well design and achieving the well objective. The work described in this paper will help in drilling high permeable sands with a high value of overbalance while eliminating the risk of differential sticking.
Reduce Collision Risk and make Informed Decision with Cost Effective Well Placement Database for Abu Dhabi Exploration Blocks
Authors: Iabbassen Nabila , El Youssef Bassem , Al Shamsi Arhama Rashed , Al Marzouqi Muna Salman
Published: October 2022

The well-collision-avoidance management principles in this paper are a summit of the work and guidelines of industry specialists from both oil operating companies and directional drilling service providers. This well-known subject in the drilling domain, the objective is to drive further the standardization of the collision avoidance rules and process in Abu Dhabi and throughout the industry to improve the efficiency and reduce the related errors.

The results of an unplanned crossing point with an existing offset well can extend from economical loss to a blowout and HSE disasters and even loss of life. well-collision avoidance principles include rules that decide the allowable well separation, directional drilling, and surveying planning in addition to quality check/ quality control procedures. The appropriation of a particular minimum-allowable separation rule does not guarantee a low collision probability. Numerous other components contribute, such as the level of compliance by office and field personnel with collision-avoidance standards and procedures, and the quality and accuracy of the directional surveys database. All these variables are linked and affect the collision risk rate.

The paper is split into many sections, each managing a specific component within the collision-avoidance process. Illustrations are displayed to highlight a good implementation of the process. This adjusted approach will improve the current practice by cover few gaps as currently only ADNOC Drilling Code of Practice Volume 3 Chapter 08 – Collision Avoidance (ADCOP V3CH08) is the unified document used by the operating companies as reference to drill safely in Abu Dhabi, but each company has it’s specific database without common database among all companies drilling in the same city.
The Benefits of an Integrated Approach (Development, Completion, Production Operation, and Integrity) for Gas-Lift Design on an UAE Offshore Field
Authors: Dwivedi Vibhuti , Al Zaabi Fatema , Jaffres Benoit
Published: October 2022

Gas lift design and optimization contributes to one of the key focus areas of whole production optimization value chain. There have been numerous methods and best practices which goes into design of a successful Gas Lift well as well as established industry best practices for the optimal operations of wells and network (facilities), but still gas lift designs derived for present or future well conditions, fail to respond to every possible operating scenario and end up multipointing, slugging or sub-optimal orifice injections.

Well completion and well Integrity are two other important focus areas which are independent from gas lift design but possess major challenges to any gas lift well. During completion of a gas lift well, traditionally GLM (Gas Lift Mandrels) carrying dummy valves are run in hole, to allow for setting packers and testing the tubing/annulus strings. These dummy valves require numerous slickline operations to be retrieved and replaced with live IPO (Injection Pressure Operated) and orifice valves, to be able to gas lift. Depending on the well completion complexity (depth, deviation) and number of gas lift valves, slickline operations performed via rig or barge may require up to 3-5 field days. Since GLV replacement operation requires the use of kick over tools, they are susceptible to incur heavy NPT's and associated HSE risks (Slickline and wireline operations accounts for major carbon footprints in upstream segment).

During gas lift operations, high pressure gas injected into casing possess enormous risks to nearby wells and surface facilities in the event of uncontrolled annulus gas leak from a single barrier envelope. Operating a gas lift well below MAASP (Maximum Allowable Annuus Surface Pressure) remains a challenge in assuring the well is operating within its integral envelope. At times it also leads to deferred production should the well needs suspended production in the event of SAP (Sustainable Annulus Pressure) or workover caused by compromised well integrity.

In this technical paper, authors will attempt to provide a holistic view of a successful Gas Lift well design by addressing the challenges raised (as above) in different phases and emphasizing on the design approach and technical solutions which were implemented, and benefits realized in terms of optimal gas lift operations, rig/ barge days and deferred production saved.
Making Non-Metallic Downhole Tubulars a Reality - Challenges & Way Forward
Authors: Hijles Ali , Waluyo Fauzia , Goh Serena L. M. , AlAdawy Ahmed , El Shamy Omar
Published: October 2022

Non-metallic pipelines are slowly replacing steel tubulars especially in Oil and Gas industry as part of the mitigation strategy to have "corrosion-free" systems, longer life service and lower total cost of ownership. In this paper, authors attempt to provide a discussion of value proposition, technology status quo and future trends, focusing on system challenges on downhole applications, and proposed way forward to build the lacking ecosystem essential to deploy non-metallic tubular downhole.

A brief discussion on current technological advancement of non-metallic pipes is supported with market trends towards higher pressure rating and higher temperature resistance pipes to meet stringent downhole well requirements. System challenges, load cases, testing requirement, financial aspect based on well construction and downhole condition are described in depth, focusing on a viable pathway to implement non-metallic tubulars in different wells throughout the lifecycle phases in different applications from water injection to oil and gas production.

This study identified the lacking aspects of a fundamental ecosystem needed to confidently deploy non-metallic pipes downhole. By addressing the R&D work necessary for the industry to focus on, efforts can be guided to fill in the missing gaps to build a fundamental ecosystem in order to replace steel tubulars gradually for desired properties. Depending on application requirement, selected non-metallic pipes are designed with various constraints and practical considerations which eventually needs to be tested and qualified for application in demanding well conditions (e.g. wet high temperature and pressure).

Other factors than pipe design play as integral component such as connection design and compatibility with existing casing and tubing accessories requires parallel development. Compatibility of connection, end-fittings, and supporting well accessories including drilling tools, completion packers, tubing and casing hangers requires thorough compatibility assurance. Logging tools, etc. are to be either delicately planned out or even require parallel development to accommodate the alternative pathway in place of traditional practices. Detailed study on how non-metallic tubular react to conventional drilling, completion and intervention activities is fundamental to ensure system integrity throughout the well construction process and well lifetime. Emphasis is placed on gap analysis of downhole infrastructure system and associated challenges to utilize non-metallic tubulars and related compatible components in drilling, completion, logging, intervention, and production conditions, as well as the lack of qualification standards for downhole non-metallic tubulars.
Integrating the Fully Coupled Geomechanical with Thermodynamics Modeling for Accurate Pore Pressure Prediction - A Case Study from China
Authors: Li Wei , Xing Yangyi , Qin Xu , Chen Weiming , Jiang Lin , Luo Tongtong , Xu Hanbing
Published: October 2022

The accurate prediction of pore pressure relates directly to various important affects oil and gas field exploration and development including drilling engineering design and formulation of oil and gas reservoir development plans. The well logging information with unique advantages such as high vertical resolution and capability of continuous measurement has been widely used in formation pore pressure prediction. Currently, though the industry has developed many methods for formation pore pressure well logging prediction, they may not be all used to calculate formation pore pressure in actual production. And it may be difficult to guarantee the prediction accuracy with a single method. In order to accurately predict formation pore pressure, this paper systematically reviewed domestic and foreign literatures on formation pore pressure well logging prediction, explained the methods and principles of each prediction technique in detail, and summarized the applicability of each formation pore pressure prediction technique in detail. This paper concluded that both the effective stress method and the Bowers method could be used to accurately predict the formation pore pressure, and the empirical statistical model method also had high prediction accuracy, while the equivalent depth method and the Eaton method which are subject to the accuracy of the normal compaction trend equation had relatively poor prediction effect. It will be a trend in this field to construct the formation pore pressure nonlinear prediction model based on mechanical parameter tests in the study area with organically integrating geophysical well logging and pressure detection data. The study area is located southwestern China, the deep formations that more than 4000 meters are high temperature (150-180 deg C). Thermal-related secondary pore pressure generating mechanism may become active leading to higher overpressure and difficulties in prediction. For the case study, an empirical relationship of overpressure impact factors versus temperature of shale was proposed. An accurate pore pressure model generated using available well-scale geomechanical model and overpressure impact factors. With an integrating fully coupled PPP model as foundation, the integrated approach helps deep wells to reduce serious wellbore instability caused by abnormal formation pressure, wellbore collapse and other complex drilling problems.
A Business-Oriented Feature Selection Method for Enhancing Machine Learning Based Digital Tools Adoption in the Energy Industry
Authors: Corneo Andrea , Suardi Mauro , Lancia Lorenzo , Cannarile Francesco , Fidanzi Alessandra
Published: October 2022

Objectives/Scope

To ensure that predictive models based on Machine Learning (ML) techniques can be fully exploited by energy plant operators, these should be trained on "actionable" features, i.e., a set of features that are explainable and on which operators can directly act to take mitigative and/or preventive actions. To this aim, we have developed a business-oriented feature selection approach which identifies actionable features while optimizing the model predictive capability at the same time.

Methods, Procedures, Process

We have developed a solution which frames the feature selection step as a Multi-Objective Optimization (MOO) problem which relies on genetic algorithms as search engine. The MOO returns a set of optimal feature subsets referred to as Pareto optimal front on which the best compromise solution in terms of model performance and ‘actionability’ must be chosen. For selecting an optimal solution from the Pareto optimal front, the TOPSIS method has been embraced which automatically ranks the candidate solutions based on their relative importance that the users assign to the two objectives to be optimized.

Results, Observations, Conclusions

The proposed methodology has been successfully applied to a real case study concerning cracking furnaces of a petrochemical plant. The optimized predictive model resulting from the application of the developed feature selection strategy has shown to be properly suited for plant operators allowing them to easily derive insights and properly take actions based on the model output. Further, due to the agnostic nature of the proposed methodology, this can be easily extended and applied to other Energy case studies where "actionability" is a driving key for the successful adoption of digital tools based on ML models.

Novel/Additive Information

To the best of Authors knowledge, the proposed approach which embeds the "actionability" property of a feature as criterium in the feature selection step and automates the process of selecting an optimal solution through the TOPSIS method, is novel from a methodological point of view in the field of machine learning applied to energy transition use cases.
Full Azimuth Multi-Rays Pre-Stack Depth Migration in the B Block
Authors: Liu Jiangtao , Yu Ming , Yu Yan , Qi Qunli , Ji Yu , Zhao Min , Chen Yingpeng , Chen Shuangting , Yang Chen , Sun Junxiao , Zhao Mingqiu , Hu Xin , Gao Junqi
Published: October 2022

Usually, the signal-to-noise ratio is low and velocity spatial change is severe in areas where fault traps develop. Seismic data processing brings challenges to geophysicists. It is extremely difficult to improve imaging in deep parts were faults harm wave propagation. Traditional pre-stack data migration imaging methods based on common middle points or common shot points are generated by the geophysical theory hypothesis. To overcome such kind of challenge and improve imaging, full azimuth multi-rays pre-stack depth migration was applied in the B block.

Full azimuth multi-rays pre-stack depth migration brings a new concept. Rays scan is generated from imaging point toward the surface, leading to a simultaneous emphasis on both continuous structure and discontinuous objects such as small faults and small-scale fractures. In this paper, a comparison was conducted between conventional Kirchhoff pre-stack depth migration and full azimuth multi-rays pre-stack depth migration. Sufficient tests have been carried out in the fault-developed areas. For geological attributes analysis, subsequent processing can be conducted on multi-domain gathers from full azimuth multi-rays pre-stack depth migration according to the request of geologists.

Application of this method in B block in the Middle East shows that full azimuth multi-rays pre-stack depth migration can improve the imaging quality of medium and deep layers and improve the imaging of small faults and small-scale fractures. Full azimuth multi-rays pre-stack depth migration can use isotropic and anisotropic velocity models to perform reflection and directional imaging in the local angle domain. Migration radius is defined by both aperture and angle. Information from all azimuths and angles is fully involved in the imaging process, which is beneficial to imaging small faults and fractures. Structural attributes such as dip, azimuth and continuity of the target zone can be obtained directly from gathers after migration. High-quality structural imaging results can be obtained by effective reflection enhancement processing on gathers from full azimuth multi-rays pre-stack depth migration. Diffraction wave enhancement processing can be used for geological fracture prediction.

This paper studies the principle of full azimuth multi-rays pre-stack depth migration, compares it with the conventional Kirchhoff prestack depth migration, analyses the advantages of this method in imaging principle and subsequent gathers processing, and applies it to seismic data of the Middle East B Block heterogeneous carbonate reservoir. The result shows that imaging accuracy of full azimuth multi-rays pre-stack depth migration technology is higher, especially in complex structural areas.
Seismic Motion Inversion Based on Geological Conditioning and Its Application in Thin Reservoir Prediction, Middle East
Authors: Xin Chen , Min Zhao , Jingbin Cui , Qunli Qi , Haisheng Yu , Xiaoliang Li , Dengyi Xiao , Shuangting Chen , Mingqiu Zhao , Bo Wang , Junqi Gao , Qiang Li , Bo Peng , Fuli An , Xiaoli Gao
Published: October 2022

With the development of exploration and development, thin reservoir prediction is becoming more and more important. However, due to the limit of seismic resolution, thin reservoir prediction has always been an important challenge in the Middle East. Thin reservoir prediction based on conventional geophysical techniques is not accurate enough to meet the requirements of development. In order to improve the accuracy of thin reservoir prediction, a new thin reservoir prediction technique is proposed.

This technical workflow main includes 4 steps: (1) Sedimentary facies identification based on multidisciplinary analysis, (2) Sedimentary facies model and seismic forward modelling, (3) Seismic response characteristics analysis and seismic data conditioning under the guide of forward modelling, (4) Seismic meme inversion and thin reservoir prediction.

The new drilled wells demonstrate the successful application of the techniques in the M field in the Middle East. The 5 layers of thin sandstones reservoir can be divided into two sets of high stand systems of sand and low stand systems of incised valley deposits. Geological model seismic forward modelling shows that the most sensitive seismic dominant frequency for effectively identifying the two groups of sandstone is 35Hz (Fig.1). Through the high resolution seismic processing, the main frequency of seismic data was optimized from 25Hz to 35Hz, which improves the recognition ability for the thin sand groups (Fig.2). Seismic facies analysis based on previous and new seismic data shows that different thin reservoir layer can be effectively identified by seismic facies. Under the constraints of seismic facies, the Seismic meme inversion can effectively predict the two sand groups (Fig.3). 51 km2 of thin reservoir favourable area was discovered and 16 wells were drilled with 91% success rate based on the new seismic inversion result in the southeast part of the oilfield.

This technology can effectively integrate geological information and seismic conditioning techniques, and improve the accuracy of thin reservoir prediction results more reasonably, which can not only provide support for the exploration for thin reservoir but also efficient development. This technique is applicable not only to thin clastic reservoir but also to thin carbonate reservoir.
The ExxonMobil Brazil Technology Collaborative: A Team of Teams Cross-Silo Leadership Experiment
Authors: Jones Gareth David , Fullmer Shawn
Published: October 2022

The value of breaking down silos to enable people to collaborate across organizational boundaries and disciplines is widely recognized. This horizontal collaboration stimulates innovation that can result in the development of new integrated solutions and business opportunities. Unfortunately cross-silo leadership is notoriously difficult to achieve. Effective collaboration across interfaces between Technology Development and Operating Units in many industries, including the energy industry, is a particularly stubborn challenge.

The purpose of this paper is to share an approach and results of adopting a diverse and inclusive Team of Teams model designed to develop and deploy technology for the exploration and development of assets in the prolific Brazil Pre-Salt play. Key design criteria for this Collaborative included: 1) Setting clear and aligned business priorities, 2) Appointing "Collaborative Connectors" multidisciplinary subject matter experts with leadership skills consummate to the challenge, 3) Identifying business unit "Technology Champions" as vested customers to help bridge across silos, 4) A multifaceted communication strategy built on transparency that fostered ideation and frequent updates on the Brazil business landscape to continuously test technology relevance and identify refinement / early deployment opportunities, 5) A conscious break with historical technology time frames and process paradigms to accelerate business application and value realization.

The Brazil Technology Collaborative experiment is deemed a success by several measures including: A leading count of business unit nominated "Technology Value Realized" KPI candidates, for example 1) the adaptation and integration of ExxonMobil reservoir characterization "Total Pore Systems" technology to reduce uncertainty on dynamic performance forecasts in complex lacustrine carbonates, 2) Improved sub salt seismic imaging and predictions of reservoir presence and quality from seismic inversion, 3) Geologic Process Modeling to help identify and constrain credible subsurface scenarios for uncertainty analysis, 4) Multiple comprehensive Pre Salt Field studies focusing on integrated dynamic characterization and reservoir performance (using publicly available Pre Salt data) and 5) Rapid assimilation of play wide data and interpretations in a practical tool to drive consistent subsurface evaluations across multiple teams and disciplines.

Beyond this Pre-Salt example, cross silo leadership in technology will be a critical capability and competitive advantage in the energy transition which demands organizations innovate and grow collaboration across internal functional boundaries and with multiple external partners.
Well Exposed Geological Outcrops Enhancing Reservoir Static Modeling
Authors: Prasad Prashveen , Balhasan Saad , Harrison Gbubemi , Khameiss Belkasim
Published: October 2022

Reservoir characterization is a critical factor in reservoir management, optimizing production, and enhancing recovery. Lack of understanding of reservoir characteristics is one of the leading causes of mistakes in constructing the static reservoir model. Understanding the three-dimensional variability of any reservoir static model requires an understanding of its depositional environment. This paper is about improving the geostatistical resolution of two or three-dimensional digital recordings by using outcrop analogs to help with small and large-scale reservoir modeling challenges. The investigation was conducted on one carbonate outcrop in Ras Al Khaimah, UAE, namely the Wadi Ghalilah formations. Initially, easily spottable characteristics of the reservoir formation were noted. Following that, the outcrop was categorized into various units. Each observed zone has provided details about the formation characteristics, the fracture and matrix network, and the lithology. Easily noticeable color changes were observed. Additionally, fossil impressions and iron-stained formations were observed at the outcrop. The layers and their thickness, matrix network, fracture network, their intensity, and orientation were observed at small-scale and large-scale. The formation characteristics hinted at the porosity and permeability of the outcrop. The observed formation characteristics and geometry properties were inputted into the static model, and subsequently, data was entered into the dynamic model to minimize the uncertainties in both the reservoir models. The areal sweep efficiency is expected to be fine during waterflooding in a small, patterned reservoir whereas water injection doesn’t appear to be a suitable option at Wasia and Thamama outcrops due to the presence of seal layers and vertical heterogeneities.
Unlocking UAE's Largest 3D Onshore Seismic Survey – Processing Challenges in Eastern Abu Dhabi
Authors: Trezzi Stefano , Seliem Abdulla , Mahgoub Mohamed , Cambois Guillaume , Glushchenko Anna , Vasilyev Pavel , Saad Al Kobaisi Abdulla
Published: October 2022

A 14,000 sq. km surface seismic survey was acquired onshore Abu Dhabi in recent years. With around 170 billion traces, it is the largest land survey shot in the UAE and one of the largest processed globally to date. We present here the methodology in processing this dataset to derive a high-resolution volume that surpasses benchmarks from previous exploration campaigns.

A detailed near surface model and related statics have been derived using Data-driven Image-Based Statics (DIBS) workflow. Over twenty depth tomography iterations were required to reach structural continuity and guarantee well matching, with strong interaction between interpreters and processing team to define a geologically consistent model.

Pre-imaging technologies such as surface wave modeling, 5D regularization to radial symmetry, Multiples prediction algorithms, as well as numerous iterations of multi-domain noise attenuation have been key to provide the desired level of Signal-to-Noise ratio and achieve high vertical resolution.

The project is also part of a broader work that aims to cover the Abu Dhabi Emirate with high-density surface seismic. Hence, the survey was designed and processed to deliver seamless merge and continuity with neighbor sectors, for a total of 40,000 square kilometers of data.

These efforts in seismic acquisition and processing have produced an accurate high-resolution volume that adds unprecedented levels of detail and a new geological understanding of key plays in the south-east regions of Abu Dhabi. This result has been achieved over established producing fields, as well as in new, unexplored areas. The outcome has been already proven accurate in the latest exploration campaigns and is currently being used as a benchmark to define possible new key targets.