bluuebunny/crossref_metadata_2025 huggingface dataset:
A New Strategy to Minimize the Surfactant Adsorption on Saudi Carbonate
Authors: Kalam Shams , Abu-Khamsin Sidqi A. , Kamal Muhammad Shahzad , Patil Shirish , Hussain Syed Muhammad Shakil , Al Shalabi Emad W. , Hassan Anas Mohammed
Published: October 2022

Surfactants play a vital role in chemical enhanced oil recovery (cEOR) to improve oil production by lowering the oil-water interfacial tension and/or altering the rock wettability. However, surfactant adsorption has been a great challenge. The quantity of surfactant loss by adsorption on a rock directly influences a cEOR project’s economics. Therefore, surfactant adsorption minimization is an important area of interest, which is investigated in this paper. Saudi carbonate rock (outcrop) was tested with a novel in-house synthesized cationic Gemini surfactant to quantify surfactant adsorption. This novel surfactant is compatible with high salinity and high-temperature environment. Rock characterization was performed first using XRD and SEM analyses, while the point of zero charge of Saudi carbonate was found using the pH drift method. Static adsorption tests were conducted using powdered rock sample and run for 24 hours to achieve the equilibration time. The material balance method was used to determine surfactant adsorption. High-performance liquid chromatography along with an evaporative light scattering detector was utilized to quantify the remaining surfactant concentration post-adsorption. Adsorption isotherm modeling was also performed to investigate the adsorption mechanism.

Rock characterization results showed that Saudi carbonate contains mainly dolomite along with some impurities like quartz and clay minerals. The point of zero charge of Saudi carbonate determined using the pH drift method was around 10. The static adsorption tests were conducted on both pure and Saudi dolomites to investigate the influence of impurities. It was found that the presence of quartz and clay particles significantly impacts the degree of surfactant adsorption on Saudi carbonates. A high adsorption of the novel Gemini surfactant used was obtained on Saudi carbonate (8.2 mg/g-rock). A powerful chelating agent made from natural, biodegradable, and renewable material was added to the surfactant solution to check its impact. The surfactant adsorption was significantly decreased using low pH chelating agent (5.8 mg/g-rock). It is proposed that low pH chelating agent renders the overall rock surface more positive and results in electrostatic repulsion between like charges of rock and surfactant. Therefore, the addition of a small quantity of the investigated chelating agent to the surfactant solution helps in reducing the cationic Gemini surfactant adsorption on Saudi carbonate. This study reports a novel strategy to minimize surfactant adsorption on Saudi carbonate through the use of an environmentally friendly and low-cost chelating agent, which will help in designing future chemical EOR projects.
A Polymer Flood Pilot with Autonomous Outflow Control Device Technology and Resilient Cost Management from South Sultanate of Oman
Authors: Al Harrasi Ameera , Badi Salim , Urdaneta Gerardo , Ramli Mohammed , Kindi Said , Sinani Yousuf , Harthy Khalfan
Published: October 2022

This paper summarizes the integrated technical learnings from the successful implementation of a polymer flood pattern and the benefits of installing Autonomous Outflow Control Device Technology (AOCD) in new long horizontal polymer injector well. It shows the result of extending this technology to unlock a pragmatic full field development, and highlight the associated benefits from a project’s perspective, leading towards huge savings and flexible operating conditions.

The polymer flood pattern consists of 3 Horizontal Polymer injectors placed in between and below 4 oil producers. The middle polymer injector was completed with Fiber optic along the well trajectory to monitor injection conformance. AOCD was deployed in the same well as part of the well completion to control and limit the flow of injected fluids into high permeable zones and improve injection conformance. The other two injectors were monitored by running Memory production Logging Tool. Following the clear observations of good conformance in AOCD well and good production gain in oil producing wells, the polymer pilot project with AOCD technology has been concluded as successful.

The Polymer flood started with a pattern in a smaller selected part of the field. Multiple surveillance techniques were implemented to ensure continuous monitoring of this. Chemical tracer sampling was done in all injectors. Memory production Logging Tool were run in 2 injectors. The AOCD technology in the middle injector showed good result where multiple Distributed Temperature Sensor surveys confirmed a good conformance and uniform sweeping in both water and polymer phases. Nearby producers showed good oil gain after injection and that supported the good sweep efficiency from implementing the AOCD technology. Also bypass valves were installed as part of this technology to enable stimulation by bullheading instead of using coiled tubing unit (CTU) which is very expensive (saving more than 150k $ per well).

The results from this pilot were very positive, with good oil gains of approximately 23 m3/day from 4 oil producers. It had been concluded that the application of the technology is successful and planned to be deployed as a baseline in all future horizontal polymer injector wells drilled for polymer fields. This paper discusses the observation of this pilot and the benefits pending the success of the AOCD Technology.

The authors have summarized the results from the polymer Pilot and presented it as a practice worth replication in a similar fields environment, due its many benefits in optimizing field development. AOCD Technology is recommended to be installed in all future polymer injectors in our field. It will be a game changer in all field to reduce the cost of stimulation and PLT, enable good sweep efficiency and support to have a continues monitoring for injectors performance.
First-Contact Miscibility Development in a High-Temperature, Ultra-Sour Reservoir Fluid System Offshore Abu Dhabi
Authors: Mogensen Kristian , Goryachev Sergey
Published: October 2022

First-contact miscibility (FCM) occurs when an original injection gas is miscible with a reservoir oil regardless of the mixing ratio. As a consequence, the displacement will remain single-phase and the microscopic displacement efficiency will be 100%. For the vast majority of field applications, FCM requires a pressure, which is prohibitively high. Some notable exceptions include ultra-sour fluids, such as the fluid system encountered in this reservoir, offshore Abu Dhabi. The exceptionally favorable miscibility conditions may help unlock further value from this challenging, ultra-sour, high-temperature, offshore field.

The swelling experiment provides a key source of information for inferring the FCM pressure. The swelling pressure curve exhibits a maximum versus the volume of injected gas and this maximum pressure is the FCM pressure. Typically, most lab experiments are terminated once the transition point from a bubble-point system to a dew-point system is observed, but for this application, much larger gas volumes were added to the system to reduce uncertainty on the inflection point. We performed equation of state (EOS) predictions to guide the experimental design in terms of the selection of gas additions. We then used the EOS formulation to conduct numerical simulations to compare the efficiency of a first-contact miscible displacement against a multi-contact miscible displacement, which can take place at lower pressures.

With numerical simulation, we show that a first-contact miscible displacement yields higher recovery compared to a multi-contact miscible displacement. We attribute this difference to the development of the compositional transition zone observed during multi-contact miscible displacement which gives rise to a gas-oil interfacial tension and a bending of the gas-oil relative permeability curves for that zone. The impact of IFT on relative permeability would depend on model parameters in the simulator. The gas utilization factor, however, reaches its minimum if gas re-injection is delayed by a couple of years, as a result of the impact of pressure on formation volume factor of reservoir oil and injection gas, respectively.
An Algorithm for Calculating Incremental Production in an Integrated Asset Model
Authors: Cunningham Peter Richard Paul , Yapp Su Huan , Leegte Hendrik Kornelis Willem , Taher Daryan Salah
Published: October 2022

Brunei Shell Petroleum (BSP) needs to evaluate project economics on 100+ further development projects for its existing, very complex production system. BSP uses a fast network-solver integrated asset model (IAM) of the entire system (900+ wells) to evaluate the effects of facility and pipeline constraints. In order to avoid time-consuming and error-prone spreadsheet-based post-processing, it was decided to extend the IAM software to include the calculation of the incremental sales profiles required for proper project economics.

There were three steps in constructing the project incremental sales calculations. The first step was calculation of physical sales profiles i.e. flows to the various sales points (export, domestic power generations) after removal of fuel and flare. The second step was defining a suitable sequence of forecasts, each adding a tranche of projects to the previous forecast. The difference in sales between a forecast and its predecessor is then the incremental sales profile for the tranche of projects new to the forecast. The final step (required because having one forecast per project would have given excessively long calculation times) is to share out the incremental sales profile amongst all the projects in the tranche. This final step required many attempts before a suitable algorithm was found.

The incremental sales profile rates were initially shared out in proportion to well-head rates. However, this gave some anomalous results. If a project required a major shut-down, then the resultant large negative rates could be assigned to a small project already in production. Consequently, one project could have an incremental sales ultimate recovery (UR) much lower than its well-head UR, while another project within the same tranche had nearly equal incremental sales and well-head URs. This problem is avoided if, instead of sharing out incremental sales rates in proportion to well-head rates, incremental sales cumulatives are shared out in proportion to well-head cumulatives. This algorithm has now been successfully in use for more than a year within BSP and other operators.

This algorithm makes it possible to calculate incremental sales profiles in a systematic and automatic way, without the need for any manual adjustments. This is one of the key steps (together with a fast network-solver) in making it possible for a shared integrated asset model to be used as a general-purpose forecasting system for a wide range of business processes, such as business planning, development planning, reserves, and operational planning.
Coiled Tubing Underbalanced Drilling Implementation Planning in Tight Gas Reservoirs (First Time in ADNOC Group of Companies)
Authors: Zain Fawad , Deshmukh Rohit Villas , Al Mteiri Nama Ali , Baslaib Mohamed Ahmed , Osama Mohamed , Elshehat Ayman , Bin Sumaida Ali Sulaiman , Abdulsalam Fouad , Ahmed Mubashir , Soliman Tarek , Mantilla Alfonso
Published: October 2022

In order to maximize the recovery from Low permeability tight reservoirs, several treatments are possible to remove post (overbalanced) drilling damage; however, the desired well performance has not been achieved. As an alternative Under Balanced Coiled Tubing Drilling implementation has been considered for ADNOC Onshore gas wells as pilot trial in attempt to counteract the invasion of drilling mud into the formation.

The recovery of (low perm) tight reservoirs is always affected by overbalanced drilling. As an alternative solution to stimulation jobs to remove the damage (skin), which has been used widely but still not getting the desired results, Under Balanced Drilling is one of the solutions to not impair the formation while drilling thus providing clean flow area/ connection. However, considering H2S contents and limitation of Well Control Barriers for Gas wells, the conventional Under Balanced Drilling is not suitable. Considering the current challenge in sour gas environment, Coiled Tubing Underbalanced Drilling is considered for pilot implementation of 3 wells in ADNOC Onshore; in which drilling of reservoir section is carried out after running the completion and continuous underbalance conditions are maintained.

This CT-UBD implementation planning included detailed planning /feasibility study and well design finalization including updating completion design. Accordingly, the well was tied-in to facilities before starting the implementation. This also included developing detailed engineering design and complete project planning including but not limited to HazID, HazOp, Engineering design, procedures finalization, contingency planning and detailed execution program.

This paper will examine a detailed approach used for planning the CT-UBD job for the first time in ADNOC Group of companies covering subsurface, operational and HSE aspects that impacted positively on the project success.
Research and Successful Field Application of Nanosilica System for Gas Shutoff in Horizontal Well
Authors: Almohsin Ayman , Hashem Hassan , Sadah Ali , Mahtani Mesfer
Published: October 2022

Innovative and cost-effective gas shutoff technologies are required to improve the oil recovery and avoid the problems associated with the unwanted gas production. A novel strong and stable material with controlled gelation time was developed to isolate gas production zones over a wide range of parameters including the temperature, pressure, injectivity duration, and flow rate.

This paper details the nanosilica for gas shutoff from laboratory development to successful field treatment. The nanosilica technology is composed of modified nanosilica and an activator which is used to trigger the viscosity of the system. The gelation time and gel strength of the nanosilica in presence of different concentrations of the activator have been investigated. In addition, the impact of the temperature on the gelation time was examined. The gas shutoff field treatment was designed to prevent the gas production from horizontal oil well based on the results obtained in the laboratory at comparable conditions.

Laboratory results revealed that the two-component system namely the modified nanosilica and the activator exhibits low viscosity i.e. 6 cp prior to the exposure to high temperature. Once the temperature is increased to certain values, the viscosity of the mixture will increase depending on the concentration of the activator such that the start point of colloid-gelling ranged from a few minutes to several hours at a given temperature. Thus, this fluid system can be placed as a single phase, low-viscosity solution into the targeted formation zones and subsequently gelled inside the formation resulting in complete plugging. For the job design, production logging tools were run on the E-coil string to detect the gas source and measure the bottomhole temperature required for the formulation of gas shutoff nanosilica, and also to measure the injection pressure to monitor the injectivity. The objective of this job is to isolate the 980 ft. of stand-alone screens. Results unveiled the great potential of nanosilica as a gas-shutoff approach to mitigate gas intrusion with a sustainable 65% gas reduction compared to pre-treatment results.

The new trend of using eco-friendly and nanoscale particles in gas control applications is a breakthrough in the oil industry. Laboratory results and field data revealed that the nanosilica for gas shutoff was effective over a wide range of parameters including the temperature, pressure and permeability.
Recent Advancements in Viscoelastic Polymer Flooding EOR Applications in Carbonates and Sandstones
Authors: Zeynalli Mursal , Alfazazi Umar , Mushtaq Muhamad , W. Al-Shalabi Emad , AlAmeri Waleed
Published: October 2022

Polymer flooding is a well-established chemical enhanced oil recovery (CEOR) technique that effectively improves oil recovery after waterflooding. Due to a large number of studies conducted in this area and extensive field data availability, this technique has gained solid practical and theoretical knowledge. Conventionally, the polymer injection is believed to increase volumetric sweep efficiency by producing movable oil that is remained unswept after waterflooding. Nevertheless, studies demonstrated that specific viscoelastic polymers might also mobilize residual oil and improve microscopic displacement efficiency, in addition to macroscopic sweep efficiency.

Although polymer flooding is an extensively applied CEOR technique in sandstones, its applicability in carbonates is still limited. This is related to the prevailing complicated conditions in carbonates including mixed-to-oil wettability nature, high heterogeneity with low permeability, and harsh conditions of high temperatures (above 85°C), high salinity (above 100,000 ppm), and high hardness (above 1,000 ppm). Recently, new polymers have been developed to overcome the challenges of harsh conditions in carbonates. These novel polymers incorporate specific monomers that protect the polymer from thermal and chemical degradations. However, the viscoelasticity of these synthetic polymers and their effect on oil mobilization are not yet comprehended and requires further investigation and research.

In this paper, we review the recent studies conducted on viscoelastic polymer flooding in sandstones and carbonates. The article describes viscoelastic polymer recovery mechanisms, polymer viscoelastic properties and the factors controlling them, and the effect of viscoelastic polymers on residual oil mobilization. This study also provides insights into the challenges faced during viscoelastic polymer flooding operations as well as field applications in sandstone and carbonate reservoirs.
Lessons Learnt from First Time Coiled Tubing Underbalanced Drilling Implementation in Adnoc Group of Companies
Authors: Abd EL Meguid Mohamed Osama , EL Shahat Ayman , Bin Sumaida Ali Sulaiman , Al Mutawa Ahmed Abdulla , Saleh Abdalla Saleh , Almazrouei Saeed Mohamed , Mantilla Alfonso , Yousfi Fawad Zain , Baslaib Mohamed Ahmed , Al Ali Abdulrahman Hasan , Al Hosani Mariam Ahmed , Al Bairaq Ahmed Mohamed , Mohamed Ihab Nabil , Ojha Aditya , Alawadhi Fatima Omar , Solaiman Tarek , Almteiri Nama , Bernadi Bondan , Rangel Pedro , Basha Maged , Cui Shuai , Jumagaliyev Yerlan , Rennox John
Published: October 2022

ADNOC Onshore initiated a pilot implementation of Under Balanced Coiled Tubing Drilling technologies for Gas Reservoirs with this being the first time in the ADNOC Group of Companies. Detailed planning was carried out for this project implementation and the onward optimization for the 3rd well based on lessons learnt was carried out.

This 3 well pilot Underbalanced Coiled Tubing Drilling, UBCTD, pilot campaign involves the sidetracking from a pre-drilled 6" hole and then drilling 3-¾" laterals with the laterals drilled in a carbonate gas reservoir utilizing UBCTD technology and methods with these being applied to eliminate formation damage, enhance production, and improve drilling performance.
A Unique High Temperature, Low Rheology Divalent Brine-Based Reservoir Drilling Fluid Improved Horizontal Drilling Performance in Hard Sandstone Formation
Authors: Kerkhoff Erik , Ismail Ahmed , Butcher Jacques , Huestis Matthew , Rekieh Aubyii
Published: October 2022

This paper describes how a dual function synthetic polymer (DFSP) additive was key to formulating a unique high temperature divalent brine-based reservoir drilling fluid (HT-DB-RDF), deployed to drill a horizontal slim hole interval through a hard sandstone formation. To efficiently drill this horizontal section the HT-DB-RDF was developed with the intent to improve drilling performance. The main parameter targeted for improvement was the rate of penetration (ROP) without compromising wellbore quality or increasing the risk of common drilling problems such as hole cleaning, wellbore integrity, drilling torque and differential sticking.

During the well planning phase, different fluid formulations, qualification approaches and field deployments were reviewed from global experience. In certain geologically similar applications, improved ROPs had been achieved using low solids and (in some instances) clear fluid systems. The most notable difference between the planned application and offset experience was the bottom hole temperature (155°C) and fluid density that was required (1.32 SG). A fluids design framework was developed from the offset well analysis and available pre-drill data. Reservoir Drilling Fluid technologies were evaluated, and laboratory work was performed to develop the system. Detailed hydraulics modelling was performed during the planning phase to confirm that the HT-DB-RDF could deliver the required performance under the planned conditions. High flow rates and low rheology were required for turbulent flow in the annulus to transport cuttings, maximizing hydraulic power to the downhole tools and drill bit and enhancing ROP.

The success of the HT-DB-RDF was assessed during execution of the well. Downhole fluid properties were used to model drill string hydraulics, equivalent circulating density (ECD) and hole cleaning ahead of the bit under the drilling conditions. Outcomes were compared to pressure-while-drilling data at the rig site to detect trends indicating poor hole cleaning. The results showed a maximum 0.01 SG variance between modelled and measured ECD, and smooth trips illustrated a clean and stable wellbore throughout. Non-fluid related operational issues resulted in a longer time to drill the interval and extended static periods during trips. The HT-DB-RDF exhibited resilience during elevated downhole temperatures. The average ROP recorded during drilling was eight times higher than the previous ROP achieved drilling horizontal offset wells.

The key technology that enabled fluid development and execution of the well was the DFSP that delivered both high temperature fluid loss control and hole cleaning capabilities. The DFSP features strongly bonded chemical linkages and cross-linked chains which achieve exceptional performance in divalent brine, facilitating high fluid densities with low solids content to maximize performance.
Divergence of Dynamometer Card Analysis from Actual Field Results at Light and Heavy Oil Fields of Mehsana
Authors: Chanchlani Kuldeep , Gogoi Ranjit , Awasthi Sukumar , Gunwant Deepak , Khanduja Nikhil
Published: October 2022

The performance of rod pumped wells are analyzed based on routine monitoring methods of echo meter and dynamometer analysis. There are 1080 sucker rod pumps installed in various fields of Mehsana. Rod pumps fail due to rod-tubing wear and aggressive fluid-reservoir conditions. Diagnostic studies are carried out promptly to predict the cause of rod pump failure. Circulation and crane troubleshooting jobs are taken post-diagnostic jobs to confirm the failure mechanism. This paper will discuss prominent mechanisms of rod pump failure, the use of dynamometer cards to track failure, and troubleshooting jobs to prevent failure.

In heavy oil fields, when the pump ceases to flow, the acquired dynamometer card showed a standing valve or traveling valve or both choked up. During troubleshooting by crane, polished rod load depicted sucker rod unscrewing or parting. The reasons for the divergence of dynamometer cards from troubleshooting jobs are the variation of fluid load due to fluid characteristics. The accessed dynamometer card indicates gas interference or gas lock despite low casing head pressure in light oil fields. During circulation job execution, the initial pumping pressure of the surface pump is quite high, which indicated obstruction across the subsurface pump. The obstruction causes no freefall of polished rod, requiring servicing by workover rig. During the pullout of the subsurface pump by workover rig, observations included downhole screen choked, gravel pack failure, wax deposition on sucker rods subsurface pump, and tailpipes choked with fine sand.

Solids incursion in light oil fields and rod unscrew in heavy oil fields are difficult to differentiate on basis of dynamometer cards. This paper will be fruitful to operators in identifying the cases, where the dynamometer card interpretation and analysis deviate from field practices.
Lessons Learned and Achievements from a Successful Sand Control Campaign in Ultra-Deepwater Gas Wells, East Africa
Authors: Martocchia Francesco , Deffieux Damien , Obanor Nelson , Battaglia Francesco , Palumbo Daniele , Rusconi Alessandro , Ricci Giovanni , Passini Lucio , Nhambi Gisela , Chirindja Joaquim , Chituto Hermenegildo
Published: October 2022

Success in deploying sand control systems is critical to guarantee the integrity of wells during their productive life. This is even more crucial when dealing with ultra-deepwater high-rate gas wells.

This paper will describe the challenges and the lessons learned from the successful 2021 completion campaign of X field in East Africa in which six gas producer wells were completed with openhole gravel pack using shunt tubes technology in water depths ranging from 1840 m to 2149 m.

The overall completion design philosophy was to rely on field-proven technologies and industry-accepted "best practices" to maximize safety and reliability. This objective was pursued in all phases of the project for timely completion of the wells while minimizing the chance of failure.

Extensive testing on formation rock cores and completion fluids was performed before the start of drilling to identify the best sand control strategy and to avoid all potential issues such as formation damage or fluid incompatibility.

State-of-the-art completion equipment was selected considering all potential contingencies associated with operations in an ultra-deepwater environment in a remote location.

This document will describe the activities carried on during the different phases of the project: design, preparation, execution, and post-job interpretation.

The goal of preventing solid production without impairing the well productivity was achieved successfully. This was confirmed from well testing interpretation where neglectable skin was detected.

At the same time, it was possible to carry on the completion activities on time and on cost despite the remote location and the challenges related to the ultra-deepwater environment.
Successful Implementation and Optimization of MLT Technology
Authors: Hilles Ahmed , Kassem Youssef Ali , Beaman Daniel , Wang Kechang , Butler Benjamin
Published: October 2022

This paper highlights the successful installation of a MultiLateral Technology (MLT) for the first time in an offshore field 40 km from Abu Dhabi. It will document the deployment of the deepest cemented MLT Level 5 globally, with improvements in well design and operations sequence compared to the conventional design and execution plan.

The system is demonstrated as a reliable method to access laterals giving the utmost importance to all operational risks concerning drilling and completion. The design relies on the Latch Coupling (LC) pre-installed with the production casing as the foundation for the successful drilling and cementing of the upper drain liner and for different completion runs. The downhole completion components that are permanently installed provide the capability for future reservoir monitoring and intervention to the laterals via coil tubing, wireline or slickline through the Multilateral Tieback System (MLTBS) completion.

The well was completed as the deepest cemented Level 5 System globally with zero NPT on MLT completion operations. The planning phase was extremely meticulous and all risks were properly identified at planning stage and mitigated during execution. The significant developments to multilateral construction are:

Optimize well profile, mud system, clean out and milling BHAs to facilitate the deployment of MTLB system. Improve the operations sequence by replacing the Retrievable Bridge Plug (RBP) run with intermediate completion. The assessed amendment has reduced four (4) trips during installation which has been recognized as a global system improvement for MLT Technology. Utilizing a glass device for the well barrier instead of slickline plugs have efficiently reduced the time and simplified the operation's intervention. Selecting to spot Hi-Vis after isolating the lateral instead of the sand has effectively improved the metal recovery and clean wellbore post clean up approach. The challenge of clean out post washover was moderated with fabricating a stinger to pass inside the packer and achieve proper debris cleaning to the seal bore area.

The well achieved its objective by providing two integral laterals with mechanical and hydraulic isolation and full accessibility of both drains for better reservoir surveillance through one single well slot. MLT installation strategy was effectively optimized to reduce time, cost and installation's risk against the original plan. The design enhancements were beneficial to achieve multiple global records.
Smart In-Situ Gas Lift System Using ICVs and Dial System
Authors: Saqib Talha , Mirza Omar Tajammal , Sabri Abdel Moez , Al-Hassan Sultan Dahi , Al-Hajri Saeed Salem , Mefleh Issam Rezk
Published: October 2022

The field that will be discussed here is a giant heterogeneous carbonate field which is located in the Arabian Gulf approximately 135 km north-west of Abu Dhabi. The field consist of multi-stacked heterogenous reservoirs. The reservoir T is the shallowest reservoir which is still undeveloped and measures 9 km by 11.5 km, with OOIP estimated in 2.3 BSTB. The reservoir is sub divided into 2 layers with the gravity 35 °API oil with initial gas oil ratio of about 350 scf/STB.

The reservoir pressure is 2,700 psi and the wells could not flow naturally due to low productivity and relatively low GOR against the high sealine pressure of more than 1,100 psi. There are only couple of solutions to produce these from this reservoir; either to lower the sealine or introduce "artificial lift".

The wellhead towers in the field are old and don't have luxury of either gas lift or ESPs. A detailed and comprehensive study was performed, and a collaborative team of engineers was assigned to find a sustainable and cost-effective solution to produce reservoir "T" in order to evaluate its potential. The team conducted a detailed and comprehensive study of the field starting from reservoir "T" and then expanded to the other reservoirs. As a result, the proposal of an "In-Situ Gas Lift" (Auto Gas Lift) pilot was formulated to use gas from the reservoir "C" (underlying reservoir T) to lighten and artificially lift the oil produced from reservoir T.

Auto Gas Lift (AGL) was selected due to the following advantages: Cost-effective artificial lift system.No surface modifications required on the wellhead towers.No additional pipeline to be laid.

The completion has been designed in a way that the gas bearing zone will be perforated and DIAL system which enhances the efficiency of gas lift through downhole data monitoring and digital operations will be installed. Dial system will allow to adjust the downhole choke any time accordingly with the minimum power and footprint requirement at surface. The controlled produced gas will allow reservoir T to flow by reducing the hydrostatic head of the fluid column in the well.

As the reservoir is subdivided into 2 layers so, the 2 drains will be drilled in each layer and their contribution will be controlled by inflow control valves (ICVs) which be equipped against each drain in upper completion. This will also allow us to flow the drains either one-by one or control commingled. But the ICVs manipulation could only be done with the portable unit with barge.

Till date the artificial lift has not been implemented in the field, however ESPs will be installed and followed by the gas lift. The data gathering with AGL will help us designing the full fledge gas lift system in the field.
Lithofacies Based Fluid Prediction Using Machine Learning
Authors: Li Yunsheng William , Ali Syed Sadaqat S. , Maskeen AbdulMohsin Abbas
Published: October 2022

Gas, oil and water zones are critical aspects for geoscientists to evaluate. In each well, a geoscientist must determine where such zones are located based on available well data, such as gamma ray, resistivity, density, neutron porosity, etc. This article addresses how to identify the most important gas, oil, and water zones based on these conventional log curvesusing machine learning (ML) technology which utilize different kinds of neural networks algorithms that is increasingly popular in well log analysis (Leila Aliouane, et al. 2013).

Traditionally, geoscientists use a combination of different log curves to identify trends to locate gas, oil, and water zones. This methodology typically uses cut-offs and/or crossovers of different log curves and it is not always reliable. The most commonly used method are the crossover of bulk density and neutron porosity and the cutoffs of resistivity, which is really helpful but not very accurate.

ML is categorized as supervised learning or unsupervised learningaccording to whether training sample labels are provided (Witten et al., 2005; Kotsiantis et al., 2007).This paper proposes a new methodology that uses MLtechnology to predict gas, oil, and water zones. It first builds an Unsupervised Machine Learning (UML) model to predict the initial lithofacies. It then builds another Supervised Machine Learning (SML) model using different conventional log curves and tested gas, oil, and water zones as inputs, including the initial predicted lithofacies from each well to train the model. The model is then applied to predict the gas, oil, and water zones for all wells, without the need for additional test information.

This automated workflow can achieve a very good result easily and accurately because the machine learning technology can fully utilize the input information to find the relationshipbetween the input data and the training data. By applying the lithofacies restriction to limit the output only within the good reservoirs,a very good final result was successfully achieved.

At the end of the workflow a 3D model was also created to predict the distribution of the fluid. The 3D model shows clearly the gas, oil and water distribution horizontally and vertically which will help with field development in the future.
Multi-Field Integrated Rock Type Framework Optimisation in Thrusted Carbonates of The Thamama Group to Reduce Modelling Uncertainty and Improve Reservoir Characterisation
Authors: Robert Matthew James , Saradva Harshil , Obaid Shams , Jain Siddharth , Jha Bhawesh Chandra , Salter Tim
Published: October 2022

Objectives/Scope

This study aims to use modern techniques to re-characterise the diagenetically altered Thamama Group reservoir units of multiple gas-condensate fields in Sharjah, UAE and determine robust rock-typing framework from the full dataset and recent core analysis program. This would be used to reduce mismatches observed in static and dynamic properties and demonstrate that a matched-outcome can be achieved with less model manipulation by focusing on textural variances within the units.

Methods, Procedures, Process

Results, Observations, Conclusions

Four petrophysical rock types were identified and found good equivalence to the identified petrographical rock types; the algorithm separated mono-modal micritic packstones from highly diagenetically altered grainstone-wackestone rudstone facies, with the rock-type clusters also being defined by Winland-r35 and Lucia poro-perm threshold lines. A single rock-typing framework, suitable for all studied fields with observed differences being explained by variability in the rock type proportions.

When compared to the previous rock typing framework and reservoir models, better matches were achieved between predicted properties and core data in QC wells. Static model property distributions were more realistic in achieving a volumetric match with produced gas. Better saturation distribution with realistic Swcr and Socr were observed by using the new Rock Typing Sw equations. Rel-perm modification for increasing water production to match the observed data was negligible due to presence of more water saturation in the crest of the reservoir. Multipliers for permeability and porosity were significantly reduced to match the well productivities and tubing head pressure estimations were improved due to less mismatch with liquid production rates.

Novel/Additive Information

This work represents the first time petrophysical and petrological rock typing was conducted for several gas-condensate fields in Sharjah, UAE. Newly acquired core data, petrographical information and core descriptions were integrated in the study.

The previous workflow, established in 1993, was updated using modern machine-learning techniques incorporating new data and a wider range of data than the previous rock typing model that was based solely on porosity measurements, remaining consistent to pore-scale and textural changes.
A Marginal Field and a Thin Saturated Lower Cretaceous Reservoir Development Through Integrated Seismic Reservoir Characterization - Onshore Case Study - Al Dhafra Petroleum – UAE.
Authors: Hassan Hany Mohamed , Elsadany Karim Mostafa , Abd El-Karim Walid Abd El-Mawla , Aly Omar , Elasrag Ramy Moahmed , Moahmed Yassien Hemdan , Sabry Yehia , Mihaljevic Ivica
Published: October 2022

Objectives & Scope

The objectives of this study are to determine new sweet spots & fluid content of the current discovery. Where, the Lower cretaceous carbonate reservoir units (Thamama) are among the most important hydrocarbon producing reservoirs in onshore Abu Dhabi. However, the studied field is considered as a marginal field, where the several cycles which affect the oil industry have emphasized the role for full integrated control of technical solutions for the development of such fields. Thus, an integrated feasibility study has been carried out to investigate the adding value of the seismic inversion and reservoir characterization. The area of study is located in southeast onshore Abu Dhabi. The studied field has been discovered and tested oil in Thamama carbonate units and is currently preparing for the first oil production.

Challenges & Procedures

Carbonates rocks are strongly modified by diagenetic process which influence the petrophysical properties to varying degrees. In carbonates, the influence of geological attributes is biased towards depositional properties in case of the use of texture and towards diagenetic attribute when using pore type.

The main challenge is to locate new save optimized candidates for infill wells securing the production plateau and minimizing the risks behind the reservoir facies/quality and seismic resolution.

To meet the objective, an integrated seismic reservoir characterization study was carried out by first a careful conditioning of the well logs and the seismic gathers data, followed by preserved AVO angle stack generation. Then, the rockphysics, fluid substitution, and wavelets estimation. The information was then used to conduct pre-stack AVO simultaneous inversion to generate several elastic attributes such as Acoustic & Shear Impedances, VpVs, and density. This was followed by detailed Litho-Porosity prediction as well as water saturation.
4D Seismic Feasibility Study for Monitoring Complex Carbonate Reservoir in Onshore, Abu Dhabi
Authors: Singh Nepal , Celma Rafael , Rappin Didier
Published: October 2022

Development of complex Upper Cretaceous carbonate reservoir of a mature onshore oil field in Abu Dhabi has been challenging because of higher pressure depletion, water cut and reservoir heterogeneities. 4D seismic reservoir surveillance technique is always challenging in carbonate reservoirs due to weak signal, therefore a feasibility study is carried out with the objective of identifying pressure depletion and the bypass oil zones subjected to different duration of production/water injection (WI) interval. Monitor seismic surveys are modeled from elastic properties derived from reservoir properties simulated at different periods using a calibrated Petro-elastic model. Seismic data acquired in 2007 is taken as base survey for monitoring field depletion during 14 years of production and future production/WI over a period of 2 to 9 years. 4D seismic amplitude attribute, "Envelope (monitor)-Envelope (base)" and "time-shift" are found above the repeatability noise (~10%) and detectability limit of 0.149ms respectively over a period of 14 years of production and 9 years of production/WI period. Technique is not found feasible over 2 years of Pilot WI period because of poor 4D signal to be detectable. 4D signals are dominantly controlled by accelerability law taken from the worldwide analogue and hence a pilot 4D monitor survey is recommended for the calibration of pressure law thereby consolidating the concept before implementing it on full field scale for optimizing the infill producers as well as water injectors.
Lower Jurassic Tight Gas Exploration Potential in Offshore Abu Dhabi
Authors: Taher Ahmed A. , Al Hammadi Mariam K. , Al Shuwaihi Muna H. , Vantala Aurifullah
Published: October 2022

The Lower Jurassic, Izhara and Hamlah formations, evaluation study has been conducted to provide an understanding of the hydrocarbon exploration potential of these formations in offshore Abu Dhabi. This objective was accomplished by evaluating the data from legacy reports and analysis the available drilling and testing results of wells that were penetrating Izhara and Hamlah reservoirs. Also, the regional well log correlation, structural settings, lithofacies variations, depositional environment models, source rocks potential were incorporated into this study. These were resulted in better understanding of the facies variations, porosity development and hydrocarbon charge system.

The timing of structural growth, the presence of indigenous source rocks, the hydrocarbon shows while drilling and the presence of high hydrocarbon saturation in the interpreted logs concluded that both the Izhara and Hamlah formations are hydrocarbon-bearing reservoirs.

The Lower Jurassic section is comprised of sequences of shallow marine mixed carbonates intercalating with shale and anhydrite streaks. These formations, although exhibits a gradual thickening from the northwest towards the southeast direction, yet they show remarkable lateral consistency, both in lithology and log response. Primary and secondary porosity are generally moderate to poor in these formations, reflecting the deep burial compaction and reflecting the terrigenous shale and anhydrite nodules with the carbonate reservoirs.

The Upper Izhara comprises of lime-mudstone and wackestone, cryptocrystalline, slightly argillaceous and occasionally dolomitic. This type of lithofacies is reflecting a similar depositional environment to that found in the Middle Jurassic Lower Araej formation, which characterized by low porosity and relatively high permeability. While, the Lower Izhara intervals is mainly comprised of shale with high hydrocarbon saturations and high porosity values. This lithology represents an unconventional potential for shale gas accumulation.

The Hamlah Formation is comprised of a variety of carbonate lithologies that are characterized by relatively low permeability which, has been deteriorated due to the precipitation of minerals from the thin streaks of terrigenous shales and the anhydrite nodules.

The evaluation of the Izhara and Hamlah formations resulted in defining high prospective areas for future exploration activities. The tightness of the reservoirs in these formations can be overcome by using multi-stage acid fracturing and long horizontal drain holes. This new technology will turn tight reservoirs of the Izhara and Hamlah formations into attractive targets for future exploration activities.

The evaluation of reservoir properties, hydrocarbon charge system, trap development and seal integrity has resulted in defining significant hydrocarbon accumulations in the Izhara and Hamlah formations in most of the prominent offshore structures.
Reservoir Characterization, Bridging the Scale from Micro to Macro
Authors: Bouzida Yasmina , Cazeneuve Eduardo Adrian , Mavromatidis Angelos , Al Ali Khalfan , Leythaeuser Thomas
Published: October 2022

This paper describes the reservoir characterization of a carbonate formation using acoustic and borehole imaging log in a novel way. Interpretation of the interplay between stratigraphic and structural reservoir elements allows additional understanding of the hydrocarbon trapping mechanism and informs decisions on the well testing program and future well placement.

High-resolution Borehole Images (BHI) have historically been one of the most widespread geological evaluation tools and they continue to be a cornerstone for providing precise data on the facies and fractures intersected by the well. The shallow depth of investigation of wellbore imaging tools can now also be usefully augmented by the acoustic, Dipole shear processing.

Patented Deep Shear Wave Image (DSWI) methodology allows identification of geological interfaces with a depth of investigation up to 110 feet away from the borehole. The processed data bridges the gap between wellbore images and field scale seismic data and so can guide meaningful reservoir descriptions and fracture characterization at the geo-cellular mode scale.

Combination of the two separate imaging measurements compensates for the limitation of each logging tool's capabilities and helps increase the range of feature detection from near borehole to as much as 110 or more feet away from the well. The statistically rich borehole imaging data can be used to help confirm the detailed characteristic of these features and how the facies/lithology affect the fracture properties. BHI also calibrate the DSWI features true azimuth, while the DSWI data can help confirm fracture hierarchies and fracture bed interaction away from the borehole.

The current study highlighted that the different scales of measurement allow additional quantified analysis of the fracture hierarchy and leads to proposal of conceptual fracture models that recognize bed-bound and non-bed-bound fractures sets. The reservoir itself is highly stratified with intercalations of limestone, mudstone and evaporite. Hydrocarbon (HC) presence, defined by an acoustic derived HC Index (but validated with conventional resistivity logging), suggests that oil is preferentially trapped in successive porous layers, but enhanced in some intervals by the additional presence of fractures. The Reservoir pressure points have indicated that only main faults-oriented NNW-SSE could potentially compartmentalized the reservoir. Additional wells and data integration are needed to confirm it.

The DSWI is also useful to calibrate the poor to moderate seismic data in this field by detecting sub-seismic features that have an impact on the reservoir and helps in updating the geological and reservoir model.