After 40 years of depletion drive, a mature, giant and multi-layer carbonate reservoir is developed through waterflooding. Oil production, sustained through infill drilling and new development patterns, is often associated with increasingly higher water production compared to earlier development phases. A field re-development plan has been established to alleviate the impact of reservoir heterogeneities on oil recovery, driven by the analysis of the historical performance of production and injection of a range of well types. The field is developed through historical opportunistic development concepts utilizing evolving technology trends. Therefore, the field has initially wide spacing vertical waterflooding patterns followed by horizontal wells, subjected to seawater or produced water injection, applying a range of wells placement or completion technologies and different water injection operating strategies. Systematic categorization, grouping and analyzing of a rich data set of wells performance have been complemented and integrated with insights from coarse full field and conceptual sector dynamic modeling activities. This workflow efficiently paved the way to optimize the field development aiming for increased oil recovery and cost saving opportunities. Integrated analysis of evolving historical development decisions revealed and ranked the primary subsurface and operational drivers behind the limited sweep efficiency and increased watercut. This helped mapping the impact of fundamental subsurface attributes from well placement, completion, or water injection strategies. Excellent vertical wells performance during the primary depletion and the early stage of water flooding was slowly outperformed by a more sustainable horizontal well production and injection strategy. This is consistent with a conceptual model in which the reservoir is dominated by extensive high conductive features that contributed in the early life of the field to good oil production before becoming the primary source of premature water breakthrough after a limited fraction of pore volume water was injected. The next level of analysis provided actual field evidence to support informed decisions to optimize the front runner horizontal wells development concept to cover wells length, orientation, vertical placement in the stratigraphy, spacing, pattern strategy and completion design. The findings enabled delivering updated field development plan covering the field life cycle to sustain and increase field oil production through adding ~ 200 additional wells and introducing more structured water flooding patterns in addition to establishing improved wells reservoir management practices. This integrated study manifests the power, efficiency and value from data driven analysis to capture lessons learned from evolving wells and development concepts applied in a complex brown field over six decades. The workflow enabled the delivery of an updated field development plan and production forecasts within a year through utilizing data analytics to compensate for the recognized limitations of subsurface models in addition to providing input to steer the more time-consuming modeling activities.

Formation Integrity Tests (FIT) or Leak-Off Tests (LOT) are common techniques to reduce the uncertainty in Fracture Gradient (FG) prediction for well planning, but are usually performed at the casing shoe. This article will discuss the first examples of open-hole LOT and FIT in Petroleum Development Oman (PDO), targeting depleted formations in water injector or oil producer wells. The data was used to justify continued drilling of slim wells with two casing strings, where otherwise three casing strings would be required, provided dynamic wellbore strengthening is applied. In addition, the concept of static wellbore strengthening was also trialed for the first time in Oman, using the hesitation squeeze testing procedure, by which the effective leak-off pressure was incrementally increased to match the maximum ECD required for cementing.

In 2015-2016, the Alkaline-Surfactant-Polymer (ASP) flood Pilot in Marmul was successfully completed with ∼30% incremental oil recovery and no significant operational issues. In parallel to the ASP pilot, several laboratory studies were executed to identify an alternative and cost-efficient ASP formulation with simpler logistics. The studies resulted in a new formulation based on mono-ethanolamine (MEA) as alkali and a blend of commercially available and cheaper surfactants. To expediate the phased full field development, Phase-1 project was started in 2019 with the following main objectives are confirm high oil recovery efficiency of the new ASP formulation and ensure the scalability and further commercial maturation of ASP technology; de-risk the injectivity of new formulation; and de-risk oil-water separation in the presence of produced ASP chemicals. The Phase 1 project was executed in the same well pattern as the Pilot, but at a different reservoir unit that is more heterogeneous and has a smaller pore volume (PV) than those of the Pilot. This set-up allowed comparing the performance of ASP formulations and taking advantage of the existing surface facilities, thus reducing the project cost. The project was successfully finished in December 2020, and the following major conclusions were made: (1) with the estimated incremental recovery of around 15-18% and one of the producers exhibiting water cut reversal of more than 30%, the new ASP formulation is efficient and will be used in the follow-up phased commercial ASP projects; (2) the injectivity was sustained throughout the entire operations within the target rate and below the fracture pressure; (3) produced oil quality met the export requirements and a significant amount of oil-water separation data was collected. With confirmed high oil recovery efficiency for the cheaper and more convenient ASP formulation, the success of ASP flooding in the Phase-1 project paves the way for the subsequent commercial-scale ASP projects in the Sultanate of Oman.

Over the last 50 years, thermal EOR has been an effective method for reducing the viscosity of and recovering heavy oil from deep reservoirs. In mature thermal EOR projects, conformance is one of the main challenges for maximizing reserves and meeting long-term production expectations. In this paper, Occidental presents a novel pilot to address thermal conformance in the Mukhaizna field in Oman. This is a thermal EOR operation in deep reservoirs (> 2,000 ft) with extremely high viscosity (>10,000 cp) in harsh desert conditions with temperatures exceeding 500°F. The pilot area is a mature thermal area with 15 years of continuous steamflood operations. The novel conformance technique, based on a combination of chemical and zonal mechanical isolation systems, was developed in-house in a low oil price environment. The pilot area consists of multiple reservoir zones that have undergone vertical steam injection since 2005. Thermal conformance has emerged as a challenge because more than 60% of the injected steam has been preferentially entering the high-permeability zones, with only 40% of the steam entering the other zones, which hold a larger amount the remaining oil. The subsurface and well engineering teams collaborated to design a rigless operation using dual coiled tubing units, one for cooling water and one pumping a chemical gelation recipe that gels at a certain trigger gelation temperature at the target zone. Zonal isolation of the reservoir is achieved using a novel inflatable packer triggered mechanically by ball gravitation through coiled tubing at 500°F and retrieved after the temporary zonal isolation. The well and reservoir surveillance included gathering data for injectivity assessment, vertical injection logging, temperature profiles, tracer tests in offset producers, and well testing for determining water cut. The pilot improved vertical conformance, as injection logging showed 40% steam reduction was achieved in the target zone, and more steam was re-allocated to the shallow zones. In addition, there was a water cut reduction of more than 20% in offset producers, and oil production tripled over a period of 3 months, which paid back the cost of the pilot and generated positive cash flow. To our knowledge, based on an SPE literature search, this is the first successful thermal conformance operation conducted with the following combination of technologies: 1) Placing a novel chemical recipe through temporary zonal isolation with an inflatable packer, and 2) Using rigless operation of coiled tubing units at harsh conditions of >500°F and high pressure >1000 psi. The outcomes open a new frontier for thermal EOR development in multi-stack reservoirs, offering better utilization of steam injection and improving mobility control over the field life cycle. The cost of the pilot project was paid off in the first 6 weeks, and all chemicals used were developed in an eco-friendly system.

In challenging times of 2020 and inconsistency with the background of a low-oil-price environment, innovative ideas needed to give a second life to all available resources such as unconventional, shallow, depleted, mature, heavy oil and by bypassed oil with a cost-effective manner (usually innovation created to fit needs). U-shaped well a combined with pigging lifting (conceptual study for new artificial lift method) is one of the selected scenarios studied under the objective of innovative, low-cost techniques to overcome many projects challenges. U shaped well accompanied with a new pigging artificial lift method are new concept studied in this lab work. Conceptual model presents many benefits of this new application such as solving most of the current wells and production challenges. The study reflects more well control with two paths, better well stimulation, low fracturing pressure and double rates, inject and lift chemical for clean without intervention, double well life "additional strings", new recompletions without rig, two horizontal side used for production or injection, step change for reservoir monitoring, improving artificial lift performance and allow creating Pigging lift "New artificial lift concept". U shaped well accompanied with a new pigging artificial lift method study shows the following progress: 1. Additional down hole barrier from the deepest point and additional open side keep the well under control more over minimize the existing well control killing procedures with low cost and risk in addition to discarding the CT operations for killing or prepare the well for W/O. 2. Decreasing stimulation pressures needs (double injection rates) and overcome the existing accessibility challenges 3. Allowing pull heading stimulation w/less displacement time and high rate and chimerical batch pumping from one side to another increase well life and eliminate PKRs risk as chimerical batches will be pigger, easier and faster. 4. Additional down hole monitoring system allowing uniform stimulation and discarding the CT operations for well stimulation and cleaning, 5. Avoiding post stimulation damage throughout fast clean-up 6. Ability to stimulate from one side with artificial lift from other side Avoiding the corrosion and erosion by faster operations 7. Allow faster plug and perf. multistage fracturing technology and overcome the unconventional well fracturing which required rate and pressure 8. Eliminate rig usage to pull the frac string to run completions 9. Step change for reservoir mentoring without S/D and real-time Logging, Sampling The deployment of U Shaped Well allows new artificial lift concept (Pigging lift) to apply. This new approach led to improved wells performance also raising efficiency of the use of the existing resources besides saving time and in return cost. This approach helps in improving well utilization and efficiency levels.

A major Malaysian offshore oilfield, which is currently operating under waterflooding for a quite long time and declining in oil production, plan to convert as chemical enhanced oil recovery (CEOR) injection. The CEOR journey started since the first oil production in year 2000 and proximate waterflooding, with research and development in determining suitable method, encouraging field trial results and a series of field development plans to maximize potential recovery above waterflooding and prolong the production field life. A comprehensive EOR study including screening, laboratory tests, pilot evaluation, and full field reservoir simulation modelling are conducted to reduce the project risks prior to the full field investment and execution. Among several EOR techniques, Alkaline-Surfactant (AS) flooding is chosen to be implemented in this field. Several CEOR key parameters have been studied and optimized in the laboratory such as chemical concentration, chemical adsorption, interfacial tension (IFT), slug size, residual oil saturation (Sor) reduction, thermal stability, flow assurance, emulsion, dilution, and a chemical injection scheme. Uncertainty analysis on CEOR process was done due to the large well spacing in the offshore environment as compared to other CEOR projects, which are onshore with shorter well spacing. The key risks and parameters such as residual oil saturation (Sorw), adsorption and interfacial tension (IFT) cut-off in the dynamic chemical simulator have been investigated via a probabilistic approach on top of deterministic method. The laboratory results from fluid-fluid and rock-fluid analyses ascertained a potential of ultra-low interfacial tension of 0.001 dyne/cm with adsorption of 0.30 mg/gr-of-rock, which translated to a 50-75% reduction in Sor after waterflooding. The results of four single well chemical tracer tests (SWCTT) on two wells validated the effectiveness of the Alkaline Surfactant by a reduction of 50-80% in Sor. The most suitable chemical formulation was found 1.0 wt. % Alkali and 0.075 wt. % Surfactant. The field trial results were thenceforth upscaled to a dynamic chemical simulation; from single well to full field modeling, resulting an optimal chemical injection of three years or almost 0.2 effective injection pore volume, coupled with six months of low salinity treated water as pre-flush and post-flush injection. The latest field development study results yield a technical potential recoverable volume of 14, 16, and 26 MMstb (above waterflooding) for low, most likely, and high cases, respectively, which translated to an additional EOR recovery factor up to 5.6 % for most-likely case by end of technical field life. Prior to the final investment decision stage, Petronas’ position was to proceed with the project based on the techno-commerciality and associated risks as per milestone review 5, albeit it came to an agreement to have differing interpretations towards the technical basis of the project in the final steering committee. Subsequently, due to the eventual plunging global crude oil price, the project was then reprioritized and adjourned correspondingly within Petronas’ upstream portfolio management. Further phased development including a producing pilot has been debated with the main objective to address key technical and business uncertainties and risks associated with applying CEOR process.

Carbonate reservoirs are highly heterogeneous and poor in interwell connectivity. Therefore, it is difficult to predict the thin oil layers and water layers inside the carbonate reservoir with thickness less than 10 ft by seismic data. Based on the petrophysical analysis with core and well logging data, the carbonate target layers can be divided into two first level lithofacies (reservoir and non-reservoir) and three second-level lithofacies (oil, water and non-reservoir) by fluids. In this study, the 3D lithofacies probabilistic cubes of the first level and second-level level lithofacies were constructed by using the simulation method of well-seismic cooperative waveform indication. Afterwards, constrained by these probability cubes, the prestack geostatistical inversion was carried out to predict the spatial distribution of thin oil layers and water layers inside the thin reservoir. The major steps include: (1) Conduct rock physics analysis and lithofacies classification on carbonate reservoirs; (2) Construct the models constrained by two-level lithofacies; (3) Predict thin reservoirs in carbonates by prestack geostatistical inversion under the constraint of two-level lithofacies probability cubes. The prediction results show that through the two-level lithofacies-controlled prestack geostatistical inversion, the vertical and horizontal resolution of thin oil layers and water layers in carbonate reservoirs has been improved significantly, and the accuracy of thin oil reservoir prediction and the analyzing results of interwell oil layer connectivity have been improved significantly. Compared with the actual drilling results, the prediction results by 3D multi-level lithofacies-controlled inversion are consistent with the drilling results, and the details of thin carbonate reservoirs can be predicted. It has been proved that this method is reasonable and feasible. With this method, the prediction accuracy on thin reservoirs can be improved greatly. Compared with the conventional geostatistical inversion results, the 3D multi-level lithofacies-controlled inversion can improve significantly the vertical and horizontal resolution of prediction results of thin reservoirs and thin oil layers, and improve the reliability of interwell prediction results. For the prediction of thin carbonate reservoirs with serious heterogeneity, the 3D multi-level lithofacies-controlled inversion is an effective prediction method.

The objective of this project is to simulate elastic logs (sonic P, sonic S and density) through a Petroelastic Model (PEM) for a complex lithology reservoir in the Middle East, that later will be used as input for a new 4D seismic feasibility study. A log conditioning (despike, depth shift, hydrocarbon correction and normalization) and comprehensive petrophysical analysis was first performed, to obtain lithology volumetric, porosity and saturation, that later were used as input for the PEM. Some wells with recorded P and S sonic log were used to conduct different cross plots of elastic properties (e.g. Vp/Vs vs. Acoustic Impedance) in order to understand how lithology, porosity and saturation affect the elastic parameters of the reservoir. After understanding and assessing the elastic behavior with the reservoir properties, three approaches to construct a PEM were tested on this reservoir. The first approach used to construct PEM applying Hashin Shtrikman (H-S) mixt, considering the solid part as a mixture of dolomite and limestone and pore space filled with a mix of oil and water. This model is limited because assumes a homogenous geometry of the pores. To address the pore geometry a Kuster Toksoz (K-T) approach was subsequently tested but the challenge was that there was no clear organization of the aspect ratio (either by lithofacies or petrophysical groups) so the original logs were used to control of the aspect ratio trough a fit function. The third approach was to use a function that models the incompressibility model of the frame (Kdry) with porosity. The result of H-S was a good agreement in the low porosity areas but in the porous intervals, it is observed that the velocities were quite high due the effect of the pore geometry that was not properly assessed by H-S. Despite reasonable reconstructions, K-T was limited by the impossibility to apply it to the wells without sonic P and S (uncalibrated aspect ratio) or a fortiori to a 3D grid. For the Kdry vs. Porosity function the result was very successful since the function is not dependent on the pore geometry, and addresses the ratio issue between solid and pore space. Then with the help of the Gassman Equation, the final Incompressibility Mix Module (Kmix) was calculated and a reconstructed sonic P and S were available for all the wells. The PEM was coded in order to deploy over a 3D property model hence a volumetric elastic model was available to assess the feasibility for new seismic acquisition.

Abu Dhabi's thick Lower Cretaceous carbonate reservoirs experience injection water overriding oil. The water is held above the oil by negative capillary pressure until a horizontal borehole placed at the reservoir base creates a small pressure drawdown. This causes the water above to slump unpredictably towards the horizontal producer, increasing water cut and eventually killing the well under natural lift after a moderate amount of oil production. Water slumping is difficult to forecast using the reservoir model. This paper showcases the successful deployment of an ultra-deep electromagnetic directional resistivity (UDDE) instrument to map injection water movement. The UDDE instrument selected for the 6-in. horizontal hole was a 4¾-in. OD multifrequency tool with configurable transmitter-to-receiver spacings. Pre-well modeling using hybrid deterministic 1D resistivity inversions was conducted for the candidate well to investigate the resistivity tool's ability to identify water slumping at distances 60-100 ft TVD above the planned well trajectory. The inversions aided the selection of optimum operating frequencies, transmitter-to-receiver spacings and BHA configuration. During operations, multiple 1D and 3D inversions were run in the cloud real time during drilling to provide simultaneous deep and shallow resistivity inversions for early identification of the water fronts and structural changes, and near wellbore changes to geosteer and maximize reservoir contact in the complex layered reservoir. Real-time 1D and 3D deep inversion results indicated the resistivity tool had a depth of reliable waterflood detection of more than 80 ft. While drilling, an interpreted subseismic fault was encountered which appeared to influence how water moved in the reservoir. Water slumped closest through the sub-seismic fault towards the well path. Past the fault, the waterfront receded upwards away from the well bore. The data proved useful for updating the static model, providing a snapshot of water flood areas, reservoir tops and faults with throw, helping to optimize the completion design to defer water production and enhance oil production. Furthermore, it captured resistivities of target, underlying and overlying reservoirs to integrate with other geology and geophysics data for better reservoir and fluid characterization near the drilled area. The positive results of this case study encouraged field-wide implementation of this technology for waterflood mapping. The information provided allowed petroleum engineers to adjust the completion design to delay water breakthrough. This proactive approach to waterflood field management improves cumulative oil production and recovery factors according to mechanistic models which have been built and tested.

Brownfield field development plans (FDP) must be revisited on a regular basis to ensure the generation of production enhancement opportunities and to unlock challenging untapped reserves. However, for decades, the conventional workflows have remained largely unchanged, inefficient, and time-consuming. The aim of this paper is to demonstrate that combination of the cutting-edge cloud computing technology along with artificial intelligence (AI) and machine learning (ML) solutions enable an optimization plan to be delivered in weeks rather than months with higher confidence. During this FDP optimization process, every stage necessitates the use of smart components (AI & ML techniques) starting from reservoir/production data analytics to history match and forecast. A combined cloud computing and AI solutions are introduced. First, several static and dynamic uncertainty parameters are identified, which are inherited from static modelling and the history match. Second, the elastic cloud computing technology is harnessed to perform hundreds to thousands of history match scenarios with the uncertainty parameters in a much shorter period. Then AI techniques are applied to extract the dominant key features and determine the most likely values. During the FDP optimization process, the data liberation paved the way for intelligent well placement which identifies the "sweet spots" using a probabilistic approach, facilitating the identification and quantification of by-passed oil. The use of AI-assisted analytics revealed how the gas-oil ratio behavior of various wells drilled at various locations in the field changed over time. It also explained why this behavior was observed in one region of the reservoir when another nearby reservoir was not suffering from the same phenomenon. The cloud computing technology allowed to screen hundreds of uncertainty cases using high-resolution reservoir simulator within an hour. The results of the screening runs were fed into an AI optimizer, which produced the best possible combination of uncertainty parameters, resulting in an ensemble of history-matched cases with the lowest mismatch objective functions. We used an intuitive history matching analysis solution that can visualize mismatch quality of all wells of various parameters in an automated manner to determine the history matching quality of an ensemble of cases. Finally, the cloud ecosystem's data liberation capability enabled the implementation of an intelligent algorithm for the identification of new infill wells. The approach serves as a benchmark for optimizing FDP of any reservoir by orders of magnitude faster compared to conventional workflows. The methodology is unique in that it uses cloud computing technology and cutting-edge AI methods to create an integrated intelligent framework for FDP that generates rapid insights and reliable results, accelerates decision making, and speeds up the entire process by orders of magnitude.

Unconventional fractured ultra-low-permeability reservoirs play an important role in continental sedimentary basins in China, and their formation characteristics and seepage laws are greatly different from that of traditional reservoirs. In this paper, the influence of microfractures and unsteady waterflooding on the productivity of fractured ultra-low permeability reservoirs are studied deeply. The reservoir parameters used in the study are from an actual fractured ultra-low-permeability reservoir in Ordos Basin, where microfractures are developed but macroscopic fractures are not. The microfractures have a small opening and are widely distributed in the reservoir, so the reservoir numerical simulation model adopts the equivalent continuous matrix model to simulate waterflooding. On one hand, the physical model of micro-fractured reservoir and the permeability tensor model of the equivalent continuous matrix are established. The results show that the existence of microfractures can increase the permeability of matrix by 1.4 times. On the other hand, an ideal heterogeneous numerical simulation model composed of pure matrix and equivalent continuous matrix considering microfracture is established according to actual geological parameters of the fractured ultra-low-permeability reservoir. To simulate and compare the unsteady waterflooding and continuous waterflooding development in 10-year development under the condition of constant annual injection rate, the results indicate that unsteady waterflooding development make higher productivity and lower water cut and lower formation water saturation than that of continuous waterflooding. By conducting unsteady waterflooding development simulation for sensitivity analysis, the results demonstrate that the greater the capillary force, the better the role of capillary imbibition in a certain range, meanwhile, the unsteady waterflooding has the best exploitation effect when the value of water injection cycle time is 100 days and the fluctuation amplitude of water injection rate is 1. At the above situation, the displacement and capillary imbibition and pressure disturbance achieve the desired effect of reducing water cut and increasing oil production.

During the progressive development of mature fields, it is imperative to drill many infill wells to accelerate production and access bypassed oil. Optimizing the infill well spacing is always the concern to reduce interference with existing wells and improve recovery. In the present study, using intelligent data mining techniques, a new analysis and visualization tool has been developed and implemented to estimate and map drainage radius by well to assess the efficiency of the current development pattern and properly plan future wells. The tool deployed several performance-based techniques to estimate the contacted stock-tank oil initially in place (STOIIP) by each existing well, and outcomes can be compared between techniques for validation. The contacted STOIIP is then converted into an effective drainage radius by well using reservoir properties from the geo-cellular model. The evaluated reservoir is subdivided vertically into pay zones drained by the wells based on geological barriers/baffles to flow and connectivity across the zones. The tool estimates drainage radii of the wells produced from the reservoir using five different methods. The resultant Proved Developed Producing (PDP) reserves polygon maps are generated for the connected zones. The drainage radii of wells with behind-casing opportunities are estimated based on correlation and adjacent wells methods, and Proved Developed Non-Producing (PDNP) reserves polygon maps were generated. Well interference density is estimated based on overlapping drainage radii polygons with adjacent well locations, which has then been validated with production and pressure data from the wells. This paper describes the methodology by which the well drainage radii and well interference density can be estimated and implemented on a selected reservoir. This workflow can be successfully used to identify drained and undrained areas around the wellbore and opportunities for additional infill wells in the various pay zones of the reservoir. This exercise observed consistency in the drainage radii cumulative distribution from decline curve analysis methods and the No-Further-Activities (NFA) simulation case.

Reservoir X is a marginal tight gas condensate reservoir located in Abu Dhabi with permeability of less than 0.05 mD. The field was conventionally developed with a few single horizontal wells, though sharp production decline was observed due to rapid pressure depletion. This study investigates the impact of converting the existing single horizontal wells into single long horizontal, dual laterals, triple laterals, fishbone design and hydraulic fracturing in improving well productivity. The existing wells design modifications were planned using a near reservoir simulator. The study evaluated the impact of length, trajectory, number of laterals and perforation intervals. For Single, dual, and triple lateral wells, additional simulation study with hydraulic fracturing was carried out. To evaluate and obtain effective comparisons, sector models with LGR was built to improve the simulation accuracy in areas near the wellbore. The study conducted a detailed investigation into the impact of various well designs on the well productivity. It was observed that maximizing the reservoir contact and targeting areas with high gas saturation led to significant increase in the well productivity. The simulation results revealed that longer laterals led to higher gas production rates. Dual lateral wells showed improved productivity when compared to single lateral wells. This incremental gain in the production was attributed to increased contact with the reservoir. The triple lateral well design yielded higher productivity compared to single and dual lateral wells. Hydraulic fracturing for single, dual, and triple lateral wells showed significant improvement in the gas production rates and reduced condensate banking near the wellbore. A detailed investigation into the fishbone design was carried out, this involved running sensitivity runs by varying the number of branches. Fishbone design showed considerable increment in production when compared to other well designs This paper demonstrates that increasing the reservoir contact and targeting specific areas of the reservoir with high gas saturation can lead to significant increase in the well productivity. The study also reveals that having longer and multiple laterals in the well leads to higher production rates. Hydraulic fracturing led to higher production gains. Fishbone well design with its multiple branches showed the most production again when compared to other well designs.

Objectives/Scope Deepest Deviated Appraisal well in Upper Khuff reservoir in a small artificial island, located about 100 KM away from Abu Dhabi shore was successfully drilled and tested. The well has been recognized as the deepest deviated well on offshore Island with highest bottom hole reservoir temperature in UAE about 375 deg F (190 degrees C) and exceeding 9000 psi reservoir pressure complemented with impurities of H2S ranging from 10-22% and CO2 between 9-20%. Methods, Procedures, Process The challenges were immense, from designing to execution, including securing special materials for the unique well design to accommodate the sour environment of Khuff reservoir as exploring new reservoirs always counter many risks comparing to developed reservoirs. The execution was driven with the focus of maximizing the ultimate value and benefit for ADNOC, our respected partners, the community and the UAE. The field is located in the most sensitive and ecological important area and is under UNESCO Biosphere reserve. Results, Observations, Conclusions The appraisal well was successfully drilled to Khuff reservoir at a depth of 19000 ft. The well test using Drill stem test (DST string) was conducted. Multiple challenges ranging from HSE, material selection, drilling and logging tools availability, limitations and procuring them in time were overcome by utilizing the World First Integrated Zero Waste Discharge Solution in Restricted & Highly Environmentally Sensitive Areas. Another major challenge faced during the drilling deeper reservoir was mud rheology changes due to high temperatures. The logging program was tailored to overcome the challenges posed by the mud, high temperature, high pressure, sour condition and to gain maximum representative reservoir data in a reservoir where high-pressure steaks and geological unconformities were anticipated. The Drill stem test, (DST) string was successfully POOH after acquiring all the objectives from Khuff K-4 testing under above mentioned harsh environment. The zonal isolation was carried out with cement and rig was released. Novel/Additive Information The drilling and testing operation was conducted with high level of cooperation and excellence accomplishing the well set objectives without (Lost Time Injury). Lessons learned are widely shared with all the teams across the region to expedite and improve on the technologies used for sour gas production. ADNOC Onshore demonstrated 100% HSE, full commitment, high collaboration and efficient outcome ensuring safety compliance for the successful delivery of this highly critical project. This paper presents the various challenges faced and overcome while carrying out the Drilling and testing of the HPHT Sour well offshore.

This study focuses on horizontal wells completed with pre-perforated liners installed in open holes, and which produce under sub-hydrostatic conditions. During workover operations, loss circulation materials (LCM) are routinely pumped, thus requiring coiled tubing (CT) cleanout interventions to enable well production afterwards. The sub-hydrostatic nature of the reservoir makes it challenging to maintain optimum bottomhole pressure (BHP) and have the ideal downhole conditions, without significant losses and with sufficient annular velocities, for an effective cleanout. During CT cleanout operations, the LCM plugging the formation may falsely create a perception that the well is able to sustain a column of fluid. However, as the LCM is cleaned out and the wellbore starts communicating with the reservoir, sudden fluid losses may occur, causing solids in the annulus to fall and leading to a stuck pipe scenario. Constant control of the balanced downhole conditions is therefore critical in such operations—yet frequently overlooked during job design. The use of real-time downhole pressure sensors thus not only ensure effective cleanout but also act as a stuck pipe prevention measure. Based on job executions in similar wells, several lessons learned were compiled. The ability to maintain optimum downhole conditions by adjusting liquid and nitrogen rates during cleanout has proven to be key to a successful cleanout. Additionally, in one of the wells where CT did get stuck, the team was able to prevent debris from falling, thus addressing the root cause, and facilitating the implementation of an effective contingency plan to get the pipe free. The need for live downhole monitoring is even more important when operating in the pre-perforated liner sections that are exposed to the open hole. Common designs calculate annular velocities based on the internal diameter of the liner, but in reality, the much bigger openhole diameter shall be taken into consideration, which result in much lower values of annular velocities in reality. Additionally, selection of the right bottomhole assembly (BHA) is critical for the overall system performance. In the presented case, the motor and mill configuration was observed to be more effective compared to a high-pressure rotary jetting tool. However, as the motor and mill combination creates significant vibrations while operating, it becomes critical to use a ruggedized version of the live downhole CT acquisition system to ensure maximum reliability. The observations compiled throughout operations enabled the development of best practices. Risks involved in a cleanout operation are often underestimated, especially in a well with a depleted reservoir. As more reservoirs face depletion in mature fields globally, the ability to clearly understand the downhole dynamics during such operations makes the difference between a successful job and a catastrophic failure.

This paper presents a summary of the deployed Smart Liner- SL equivalent to the Limited Entry Liner- LEL as lower completion for the first time in a sidetracked Gas well, Offshore Abu Dhabi. R-1 is subdivided into several sub-layers, the reservoir properties are characterized by low porosity & low permeability (Tight). Reservoir quality in the Upper part is better in terms of porosity & permeability than the lower part. The gas production is mainly from top part of R-1 reservoir, no contribution from Lower part. In 2017, Data gathering was conducted on well A-1 (Coring, Logging & Pressure Points). Actual Gas production Offset wells are restricted from optimal production due to Well Integrity Sustainable Annulus Pressure, to compensate the restricted aged wells due to Well Integrity, Gas production can be increased to 3 times using SL as a stimulation method. The Smart Liner was selected as a lower completion and as a stimulation method for better flow distribution, improved well performance, effective Acid stimulation, also to ensure hole accessibility, allowing aggressive bullhead stimulation at high rate/pressure and high acid concentration at less time ~ 1.5days/job, in addition to eliminating high risk and high cost Coiled Tubing (CT) intervention for stimulation. The first step was to design the SL Completion Workflow with a representative well trajectory for the selected well to be fed and reservoir properties to be extracted from the dynamic model, and then to create a representative stimulation model utilizing property numerical software with all possible scenarios; open hole that represents PPL and suggested SL compartmentalization and holes distribution based on reservoir parameters along the lateral. Once the well model is created, different scenarios for different completion designs are to be run versus different acid concentrations and volumes till achieving the optimum results from stimulation point of view in addition to formation and facilities limitations. Drilling operations were very challenging; fortunately, we succeed to deploy the SL after final adjustment based on FMI Natural Fractures. The Smart Liner as stimulation has proved to be a cost-effective solution for gas wells comparing to advanced stimulation methods in addition to eliminating the high risk and high cost of the Coiled Tubing (CT) intervention for stimulation a huge savings in well construction with maximizing performance.

Drilling a multilateral well is generally recommended for several reasons such as achieving higher productivity indices and improving recovery in tight, low-permeable zones. While the many benefits of multilateral wells are attractive, they also have drawbacks which make these wells challenging. A key challenge is how to effectively stimulate all the laterals after they have been drilled. This paper presents the application of a unique intervention technique in a multilateral well to stimulate several laterals in a single run. To increase reservoir contact area the operator drilled a multilateral well composed of 4 legs. This was carried out despite the absence of proven ways to stimulate each lateral individually. This intervention would also present the following challenges: Well displacement and stimulation would require multiple re-entries into each lateral, all conducted from a drilling rig. All the laterals were known to branch off from the low side of the bore, so individual lateral and main-bore selection would be complex. Extended reach laterals require accurate friction lockup modelling and mitigations. The unique solution presented in this paper includes the use of real-time Hybrid cable coiled tubing (RTHCT) technology. This incorporates a hybrid cable installed in the coiled tubing (CT) string and a modular sensing bottom-hole assembly (MSBHA). Electrically controlled indexing tool, inclination sensor, tool-face sensor, and hydraulic knuckle joint were used as part of the BHA to enable real-time diagnostics and dynamic controls from surface to successfully enter the lateral legs. The MSBHA enabled the orientation of the BHA electrically to any position required using software to determine and control the exact position of the BHA. This paper presents a solution to all the above-mentioned challenges. It discusses the successful implementation of the RTHCT to displace and stimulate all the 4 laterals in a single CT trip in less than seven days, pumping over 7,000 bbls of various chemical systems and covering an open-hole length of 11,176 ft. Unlike other technologies, the RTHCT technology confirmed entries into the laterals without the need to tag the bottom of the lateral, saving substantial time. Enabling re-entry in these 4 laterals represented a world record translating into major efficiency improvements and cost savings for the project. This intervention also represented the first time in Kuwait that more than 2 laterals have been accessed in a CT run.

Global experience in cold Gas Oil Gravity Drainage (cGOGD) recovery with crestal gas injection of infield produced gas is very limited, but is a proven economic recovery method for fractured carbonate reservoirs in North Oman. Despite decades of research in nature of fluid flow in fracture-matrix media and application of sophisticated tools in building fracture model of a naturally fractured reservoir (NFR) reliable prediction of the GOGD production performance often proved elusive. Characterization of fracture networks and modeling of matrix-fracture transfer function, gravity induced fluid flow in heterogeneous matrix media especially in case of capillary discontinuity due to tight interbedded matrix and capillary pressure hysteresis are the key challenges for reservoir modeller. Re-infiltration of oil into lower matrix blocks, matrix permeability, fracture density and spacing, wettability and reservoir fluid properties have significant impact on the well and field performance. The risk posed due to undermining the key modeling parameters have huge implication on facility design, subsurface concept and value of the project. The challenges in upscaling the fracture properties in a range of grid scale, experimental design for history matching and uncertainty analysis, understanding the oil rim development in leached zone and numerical options are some of the key aspects which have been illustrated in this paper. The field being on primary production since 1985, showed poor recovery and high water cut. Multi-episodic tectonic events resulted in variable fracture intensity and fracture permeability anisotropy. This study investigated the effects of the parameters on cGOGD recovery process, operating strategy (e.g., gas injection rate and liquid offtake) and on the overall field performance. The development decisions are not simply relied upon the dynamic simulator results, but an integrated understanding from comprehensive analytical calculations for multiple recovery mechanism such as fluid expansion, fracture oil displacement, gravity drainage from background matrix and leached zone and analogue field GOGD performance were taken into consideration. The subsurface development decisions such as producer location with respect to faults and lineament, well pattern & spacing, producer depth, gas injector locations, gas injection scenarios, aquifer pump-out wells and maximum off-take rate were analyzed and optimum decision could be taken from multi-scenario modeling studies. The GOGD development could increase the field recovery up to ~9% at low UTC and positive NPV. A pragmatic and integrated modeling workflow with multi-scenario modeling approach was pursued to address the development risk which facilitated the field to be economically developed. The key modeling challenges have been highlighted for GOGD modeling process with gas recycling option of development which can be replicated in similar fields in PDO.

To meet the current oil and gas market challenges, there is an industry need to optimize cost by safely drilling longer horizontal wells to maximize well productivity. Drilling challenges include the highly deviated trajectory that starts from the surface sections and wellhead, the high DogLeg Sevirity (DLS) profile with collision risks, and the thin complex geological structures, especially in new unconventional fields where numerous geological and geomechanical uncertainties are present. To mitigate for those challenges, reviewing the existing drilling techniques and technologies is necessary. To compete in the current Hi-Tech and Automation era, the main challenges for directional drilling service providers are to reduce well time, place wells accurately, and improve reliability, reducing repair and maintenance costs and helping the customer reduce time and costs for the overall project. Offset wells analysis and risk assessments allowed identifying the main challenges and problems during directional drilling phases, which were highlighted and summarized. As a proposed solution, the new generation of intelligent fully rotating high dogleg push-the-bit rotary steerable system has been implemented in the UAE onshore oil and gas fields to improve the directional drilling control and the performance. This implementation reduced the Non-Productive time (NPT) related to the human errors as the fully automation capabilities were being utilized. The new rotary steerable system has the highest mechanical specs in the market including self-diagnosis and self-prognosis through digital electronics and sophisticated algorithms that monitor equipment health in real-time and allow for managing the tool remotely. As a result, the new intelligent RSS was implemented in all possible complex wellbore conditions, such as wells with high DLS profile, drilling vertical, curve, and lateral sections in a single trip with high mud weight and high solid contents. Automation cruise control gave the opportunity to eliminate any well profile issues and maintain the aggressive drilling parameters. Using the Precise Near-bit Inclination and Azimuth and the At-Bit Gamma real-time data and high-frequency tool face measurements in the landing intervals where required for precise positional control to enable entering the reservoir in the correct location and with the correct attitude helping the customer's Geology and Geophysics department to place wells accurately while maintaining a high on bottom ROP.

The aim of this study is to demonstrate the value of an integrated ensemble-based modeling approach for multiple reservoirs of varying complexity. Three different carbonate reservoirs are selected with varying challenges to showcase the flexibility of the approach to subsurface teams. Modeling uncertainties are included in both static and dynamic domains and valuable insights are attained in a short reservoir modeling cycle time. Integrated workflows are established with guidance from multi-disciplinary teams to incorporate recommended static and dynamic modeling processes in parallel to overcome the modeling challenges of the individual reservoirs. Challenges such as zonal communication, presence of baffles, high permeability streaks, communication from neighboring fields, water saturation modeling uncertainties, relative permeability with hysteresis, fluid contact depth shift etc. are considered when accounting for uncertainties. All the uncertainties in sedimentology, structure and dynamic reservoir parameters are set through common dialogue and collaboration between subsurface teams to ensure that modeling best practices are adhered to. Adaptive pluri-Gaussian simulation is used for facies modeling and uncertainties are propagated in the dynamic response of the geologically plausible ensembles. These equiprobable models are then history-matched simultaneously using an ensemble-based conditioning tool to match the available observed field production data within a specified tolerance; with each reservoir ranging in number of wells, number of grid cells and production history. This approach results in a significantly reduced modeling cycle time compared to the traditional approach, regardless of the inherent complexity of the reservoir, while giving better history-matched models that are honoring the geology and correlations in input data. These models are created with only enough detail level as per the modeling objectives, leaving more time to extract insights from the ensemble of models. Uncertainties in data, from various domains, are not isolated there, but rather propagated throughout, as these might have an important role in another domain, or in the total response uncertainty. Similarly, the approach encourages a collaborative effort in reservoir modeling and fosters trust between geo-scientists and engineers, ascertaining that models remain consistent across all subsurface domains. It allows for the flexibility to incorporate modeling practices fit for individual reservoirs. Moreover, analysis of the history-matched ensemble shows added insights to the reservoirs such as the location and possible extent of features like high permeability streaks and baffles that are not explicitly modeled in the process initially. Forecast strategies further run on these ensembles of equiprobable models, capture realistic uncertainties in dynamic responses which can help make informed reservoir management decisions. The integrated ensemble-based modeling approach is successfully applied on three different reservoir cases, with different levels of complexity. The fast-tracked process from model building to decision making enabled rapid insights for all domains involved.