In a deep gas drilling project, landing the 7" liner at the top of a thin carbonate layer is critical to ensure ease of drilling and maximize reservoir exposure. Real-time multi-layer bed boundary detection technology was utilized to enhance top of reservoir detection certainty. This approach reduces the hard caprock interval in the next section which potentially causes wellbore instability and downhole tools failure, allowing drilling long reservoir section with minimum BHA runs. Picking the top of caprock using conventional approach was challenging due to the lack of control points and the absence of distinct markers to distinguish the reservoir from the caprock. The variations in formation thickness and structural complexities also generated uncertainty in well correlations. Past experience was a series of downhole tool failures, resulting in multiple BHA runs to drill the reservoir section. Drilling caprock too deep could also accidentally expose the reservoir which would have catastrophic consequences such as total losses, well control situation, and sometimes missing the sweat zone completely. The initiative comprised the introduction of a multi-layer detection resistivity mapping tool to detect bed boundaries with resistivity contrasts in the 8-3/8" hole section. The objective was to set the 7" liner as deep as possible to minimize the footage in the caprock in the next 5-7/8" section. Combined with in-depth well placement study to determine best trajectory for landing strategy, it enabled to push liner point closer to top of reservoir. In subsequent implementations of this novel approach, the 8-3/8" section was deepened in average by 20 ft TVD into the caprock against the default 5 ft TVD previously followed. The drilling performance in the subsequent 5-7/8" section was significantly enhanced. Minimum shocks and vibrations were observed, and maximum drilling parameters could be applied at section start resulting in much higher penetration rates. The reservoir section was successfully drilled in two runs, doubling the average footage drilled as compared to previous similar runs. From a reservoir management viewpoint, the initiative contributed to increase the net-to-gross ratio across the pay-zone which improved the efficiency of the frac stages and eventually expanded the overall gas production. This accomplishment was only made possible by the collaborative approach between the integrated services provider and the other stakeholders and was first deployed in a deep gas integrated drilling project. The client gave very positive feedback and the gas drilling unit is now considering implementing similar strategy in other rigs. From these promising results, it is believed that this initiative can also be implemented elsewhere in the Middle East where accurate well placement across thin carbonate layers is critical for successfully drilling the reservoir section.

Exploration is a high risk business. Hence, available data including those from offset fields have to be analyzed and reviewed critically prior to drilling a well. This becomes especially true in a marginal thin reservoir where innovative drilling and testing strategy would play a key role in deciding commercial discovery of the prospect. Flow rate is one of the basic criteria, inter alia , on which commercial viability of a prospect depends. Conventional testing strategy performed in the vertical well did not yield commercially viable flow rate. Hence, innovative approach was adopted to achieve the desired results. After drilling, multi-disciplinary data should be integrated to finalize the testing strategy, which is critical to announce the discovery to meet the criteria set by the company. Reservoir of interest is a thin clastic reservoir, which could not meet the criteria of flow rate during testing with conventional way even though volume in place assumed to be significant due to large area. After carefully reviewing all data, the flow rates were predicted with the modeling if well will be horizonalized. In order to fully evaluate the prospect, the static and dynamic model of the first vertical well was thoroughly reviewed and re-evaluated. The vertical well was tested comingled with two reservoirs having a two feet dense layer between the two. The well flowed mostly water with traces of oil. A detailed review of the test data revealed that a higher prospectivity layer exists in the overlying thin clastic reservoir above the dense and that the two reservoirs are in isolation. Based on this finding, a modeling was performed to decipher optimal horizontal well length to achieve the flow rate. It was a challenge to geo-steer the well trajectory of horizontal section in this very thin reservoir, which was successfully achieved by an active coordination of an integrated teamwork. An innovative approach was adopted by applying Wireline Formation Tester (WFT) data to confirm dynamic isolation from underlying reservoir, which is predicted to be major water contributor. Optimal horizontal well length was established by analytical model for achieving the best flow rate. The well was drilled successfully with horizontal length of 1400 ft. in thin clastic reservoir and completed with fit-for-purpose completion followed by production testing that achieved the flow rate criteria as predicted in the model. This paper summarizes the processes of: (1) data integration, (2) establishing reservoir segmentation based on static and dynamic data, (3) modeling to predict flow rate and optimal horizontal length, (4) selection of fit-for-purpose completion and (5) addressing challenges and lessons learnt during planning and execution phases.

The Sabiriyah Mauddud calcareous reservoir, located in North Kuwait is one of the major hydrocarbon assets in the country. A study was prepared in order to maximize production by implementing a multilateral, multi-zones well path. The paper discusses the methodology for the planning and execution of the first in its class Mauddud reservoir multilateral producer. This study illustrates the implementation of a unique approach for a challenging well design, including two lateral sections (L0 & L1) in a complex reservoir structure targeting multiple zones. Precise and continuous monitoring of the directional measurements was essential for the successful delivery of the mother wellbore, while fulfilling project constrains. The bottom hole assembly (BHA) used in the 6-1/8" horizontal sections was comprised of a rotary steerable system (RSS) with near bit gamma, azimuthal deep resistivity distance-to-boundary technology, and near bit density/porosity. Specialized software were used in creating geo-navigation models of the target reservoir zones. The real-time dynamic interpretation of the structure morphology was key in order to maximize exposure of the productive zones while minimizing the contact with non-productive zones. The openhole sidetrack technique for the startup of L1 involved a detailed procedure, and a special feature designed into the well plan to facilitate the sidetrack in the desired zone. Water based mud was used to optimize logging while drilling (LWD) measurements in order to clearly predict fractured zones, while mud weight recommendation and pressure hazard identification was based on geo-mechanical analysis. The well was successfully executed, tripling the production when compared to a single horizontal producer recorded in the same reservoir zones. The sidetrack procedure implemented allowed to initiate the drilling of L1 with the same bottom hole assembly (BHA) from L0 without pulling out of the hole, this approach considerably helped to save rig time. The positioning of the LWD sensors close to the bit significantly reduced the reaction time and minimized the challenges induced by sudden changes in reservoir properties. Similarly, the enhanced geo-navigation technique of integrating near bit density/porosity and the azimuthal deep resistivity distance-to-boundary technology played an important role in successfully navigating the wellbore within the multiple reservoir zones with confidence. This multilateral well has proven the concept of implementing shorter lateral sections to target multiple zones of interest, aiming for enhanced production when compared to projects with single longer laterals. The novelty of this work is the optimized methodology established for hydrocarbon extraction from a challenging reservoir. The implementation of these sidetrack procedures combined with enhanced geo-navigation techniques resulted in optimum well placement and the successful delivery of the first multilateral, multi-zones producer in North Kuwait.

The development of marginal volumes in the Jasmine field is part of Mubadala Petroleum's overall strategy to extend the field's life. This development is accomplished by progressively exploiting increasingly challenging prospects. This paper highlights two case studies to illustrate how Mubadala Petroleum has successfully developed marginal prospects to unlock the Jasmine field's remaining potential. Prospect identification begins with integrated subsurface studies focusing on contingent resources. Several studies were conducted to determine the right technology to mature these marginal prospects. These prospects often involve the requirement to drill Extended Reach Drilling (ERD) wells. This is due to the fact that some platforms are slot constrained, such that wells cannot always be drilled from the nearest platform. One of Mubadala Petroleum's solutions was to drill a horizontal well with a completion that uses an Autonomous Inflow Control Device (AICD) to optimize and enhance oil production. This combination of AICD and ERD horizontal wells has proven successful in the Jasmine field's continuing development. Two wells in this case studies were drilled during the 2018 and 2019 drilling campaigns, illustrate how marginal volumes are developed in the Jasmine field, with each case having unique objectives and challenges. In 2018, one horizontal well was drilled, with an aim to enhance recovery efficiency in the viscous oil reservoir. The well was drilled close to the top reservoir, AICD devices were installed in conjunction with a sand screen to delay water breakthrough, and the well has been in production for two years. The overall strategy was effective in delaying water breakthrough. In 2019, a horizontal well was drilled to develop a relatively small 14ft oil rim below a thick gas cap reservoir. This well was the longest ERD well in the Gulf of Thailand. The well was also successfully drilled and geosteered at 4-5 ft TVD below the gas cap. AICD's were installed to balance the gas cap expansion and aquifer support to optimize oil production. The well has produced at a stable oil rate of 500-600 bbls per day with minimal gas and water production, up to the present date, confirming the validity of AICD technology in reducing the production of unwanted fluids. The AICD has been shown to play a significant role in optimizing production in reservoirs with small oil rims and thick gas caps. AICD completions also help to enhance production recovery from viscous oil reservoirs. Moreover, ERD drilling has improved the feasibility of several remote prospects and minimized the slot availability constraint in the Jasmine field.

Drilling and completing wells for hydrocarbon production comprise the major cost of well operations. Slim-hole drilling can significantly reduce drilling costs, making low producing reservoirs economically viable. However, a number of challenges are associated with slim-hole wells. A major challenge encountered while deploying lower completions in long horizontal slim-hole wells is stuck pipe, as the wellbore diameter is less than six inches, allowing restricted clearance between the wellbore and completion equipment. Stuck pipe incidents can cause significant non-productive time (NPT), additional high costs, and the possibility of compromising the well objective. Stuck pipe incidents may require sidetrack operations in the worst cases, which may considerably change the planned well design and delay the overall project, along with increasing costs. Drilling in the minimum stress direction with heavy mud weight and high overbalance pressure adds to the challenge in deploying completions in HPHT slim-hole wells. While deploying the lower completions in slim-hole wells, many factors come into play and each factor has a critical role in the success of the operation. After conducting a detailed study on several HPHT slim-hole gas wells in Middle-East region, a risk matrix was developed for a specific well-bore diameter, by identifying some common variables. Based on potential chance of occurrence, a certain value was assigned to each variable. The risk mitigation plans are driven by the risk matrix variables. Using this risk matrix, the occurrences of stuck pipe incidents in critical HPHT slim-hole wells that initially tend to have high chances of stuck pipe were significantly reduced. The risk matrix presented in this paper successfully mitigated stuck pipe incidents from occurring and has saved millions of dollars in associated costs. The matrix played a key role in operator's drilling operations and was adapted in operations as an important tool to evaluate final wellbore conditions prior to selection of the optimum completion type. This paper presents a highly effective risk matrix that significantly minimizes stuck pipe incidents during drilling/completion operations of slim-hole gas wells.

Frequent drilling challenges for high-inclination well paths in the overburden Laffan and Nahr-Umr shales involve stuck pipe incidents and caving, leading to sidetracking in extreme cases. Advanced geomechanics studies including both an anisotropic wellbore stability model and shale stability analysis were conducted on acquired cores to better understand these problematic intervals for improving drilling efficiency and reducing costs by mitigating wellbore instability. The study analyzed the preferential directions of deformation and failure (i.e., anisotropic) in the shales and their time-dependent behavior in reacting with drilling fluid. Shale samples were preserved to avoid changes in mechanical properties due to the high clay content and low permeability. Two overburden shale intervals were analyzed to determine strength and elastic anisotropy. Dynamic anisotropic elastic properties were obtained via ultrasonic wave propagation. Strength anisotropy was evaluated using the plane of weakness model that assumes a heterogeneous media composed of a matrix rock and plane of weakness (e.g., bedding/laminations, interface between lithotypes or laminations). The test results showed a drop of compressive strength from 50% to 70% for samples with inclination from 38 to 62 degrees, which increases the chance of formation collapse of the laminated shales at such wellbore deviation. The anisotropic analysis proved that the stress field is higher when anisotropic properties are considered, which leads to higher propensity for failure. Shale stability tests demonstrated that most of the instabilities identified in the Laffan and Nahr-Umr formations were mechanical in nature. The optimal mud weight is strongly dependent on the well trajectory to account for the plane of weakness and strength anisotropy. Combing data from laboratory tests with advanced sonic logs enabled a more robust evaluation of the formation anisotropy at the well scale, which improved both stress predictions and mud-weight window predictions along the well trajectory. This anisotropic well-centric model helped for determining more appropriate mud weights and salinities for upcoming directional wells. By obtaining core samples in the shale formations, the operator was able to test and characterize the anisotropic behavior and also analyzed the time-dependent behavior. These results were combined with advanced sonic logs to better understand and mitigate wellbore instability induced from the plane of weakness.

Unmanageable losses through carbonate formations led to pumping water through the drill pipe and heavy mud cap in the annulus to drill with total losses. Although this technique overcomes the need to fly mix drilling fluid, it adds the complication of pumping heavier mud cap into the annulus. Pressurized Mud Cap Drilling (PMCD) was introduced the first time in the project to eliminate the requirement of mud cap for improve wellbore condition, efficient well control and to optimize the overall cost while drilling with total losses. As mud cap density increases based on reservoir pressure, so does solids concentration in mud cap. Apart from mud cap getting extremely expensive at higher densities, it deteriorates hole condition due to continuous addition of solids especially for horizontal wells where solids keep piling up on the low side of the wellbore. With total losses in the reservoir, drilling is followed by image log, followed by reaming run and finally open hole completion runs to isolate those fractures. On wells where higher density mud cap was used, severe hole problems leading to stuck pipe were faced either during logging or open completion runs. On most of the occasions, solids of mud cap have been proven as the root cause for worsening the situation. PMCD has been introduced as a solution to such high-pressure wells to drill and complete them with total losses more efficiently and cost-effectively. It not only reduces the volume of solids dumped in the wellbore in the form of mud cap thus improving the hole condition but also saves the immense cost of mud cap which is especially massive for long laterals while dealing with long reaming operations. The above motivation of finding a solution for drilling in total loss environment emerged from one of the wells where pipe conveyed logging string (TLC) got differentially stuck while pumping a 90 pcf mud cap. The pipe could not be recovered even after cutting it inside the casing shoe confirming it was packed off with solids laden mud cap. The well was sidetracked and was completed with PMCD successfully without any complications. After that job, PMCD has been implemented in five other land wells successfully and being recognized as standard practice for drilling high-pressure wells with total losses. This paper illustrates the challenges faced by turn key project team due to total losses and drilling with mud cap, and overview of PMCD procedures, comparison of mud cap and the inherent advantages of PMCD over mud cap drilling. It provides details of the well which could only be recovered using PMCD after sidetrack due to stuck pipe.

This paper summarizes the integrated technical learnings from the successful application of a an Autonomous Inflow Control Device (AICD) in new long horizontal wells producing heavy oil in multiple fields and show the result of extending this technology to the old producers in the field. It details the facts and observations that multidisciplinary authors have captured. The AICD was completed in more than 40 new oil wells in multiple fields. It comprises of mechanical devices installed with the sand face completion, which react in real time to the properties of the flowing fluids, decreasing/delaying the water influx from high productivity zones, promoting increased oil production from other compartments of the formation, therefore, equalizing the drawdown along the horizontal section of the well and performing a dynamic water shut-off operation. The great successful result from new oil wells with this technology AICD opened the door to do few trials in existing producers. The AICD-completed wells showed initial water cut in the range 1% to 2%. Which had reduced significantly in comparison to nearby analogues. The initial net oil rate resulted to be more than 2 times of the expected one, with an acceleration of ~10,000 bbls of net oil during the first month. After the initial production period, the technology is still delaying the aggressive water cut development usually observed in these fields, having provided 2 times the expected net oil rate during the first 3 months, with an acceleration of approximately 20,000 bbls of net oil over this period. It has been concluded that the application of the technology is successful and already deployed as a baseline in all future horizontal wells drilled. Also this technology was tried in old producer wells and already 15 wells completed with AICD completion which shows good reduction in gross/water and increase in oil production in some of the wells by more than 30%. With these successful results, 35 wells from existing producers were planned to be completed by AICD in 2020 from multiple fields. The authors have summarized the results from the AICD deployment and presented it as a practice worth replication in a similar heavy oil environment, due its many benefits in optimizing field development. AICD in new and old wells will be a game changer in all filed to reduce the water and increase the oil.

In the context of high hydrocarbon price volatility on the global market and worsening resource structure an increasingly greater attention is paid to the search of effective and economically sound tools for production and exploitation process management and control, including in horizontal and directional wells. Traditional approaches to horizontal well surveys by PLT using CT come with low industrial safety of work performance, high cost and, therefore, limitation in wide use. One of the alternative approaches is to use well marker monitoring system enabling to obtain unlimited information about inflow profile and composition along a horizontal well without interventions on a long-term basis. This paper describes an approach of placing the marker monitoring systems as a part of completions and carrying out 3-phase monitoring for oil, water and gas, including off-shore project conditions.

A giant carbonate field offshore is being redeveloped using extended-reach horizontal laterals, up to more than 20,000 ft. with open-hole un-cemented liners, drilled from artificial islands. Previously, SPE171800 introduced an innovative Limited-Entry Liner (LEL) design that enables high rate aggressive stimulation of these wells by bullheading. These wells provide significant profitability in unit development cost, though it is critical to effectively stimulate the entirety of the long laterals to maximize reservoir recovery. Recently, Sau et al. 2019 presented our first application of real-time fiber optic surveillance during the successful stimulation of a water injection well with a 12,000 ft LEL lateral section. Fiber optic distributed temperature and distributed acoustic sensing (DTS/DAS) data were collected. Qualitative analysis of the real-time data were compared with a subsequent production logging tool (PLT) to confirm the effectiveness of the LEL completion and also the validity of the real-time fiber optic data. This current paper describes the detailed analysis of the DTS/DAS dataset collected and the information that can be extracted from it regarding the effectiveness of the well stimulation. Also presented here is how DTS/DAS can be used to monitor the completion performance during injection; quantitative DTS/DAS analysis provides detailed insight into the acid volume injection into each compartment as well as post-stimulation water injection profile over time and at different injection rates. Recommendations are made regarding how to use the data from future DTS/DAS enabled stimulation jobs to extract the most value from real-time measurements and how permanently installed fiber optic DTS/DAS systems can be used to monitor the health and performance of such extended-reach injection wells.

Generally, appraisal wells are drilled to reduce uncertainty. However, occasionally reserves uncertainties may increase in a heterogeneous carbonate reservoirs specially challenging stratigraphic limit of reservoir facies. Under such circumstance, sometime operators rethink of further investment in the field development when in-place volumes are marginal. The objective of the study is to present how we achieved well design modification and test strategy in a dynamic environment. Optimal well test design, execution and analysis can help mitigate major uncertainties, which were not considered during initial planning phase The subject appraisal well was drilled as a vertical hole in an up dip direction to the first appraisal well. However, Open Hole (OH) and mud log data indicated the reservoir to be tight and in some portion dominated by water flow during sampling even though clear hydrocarbon presence observed in core chips and cuttings analysis. After detailed studies of the available data, a decision was taken to horizontalize the well towards first appraisal well. While drilling, geological barriers were encountered as indicated by the presence of different fluids in the horizontal section. Variable fluid presence (water and oil) posed a challenge with respect to well completion and testing. This paper describes the process of completing the well in an evolving complicating situation and how successful well test design and execution helped to mitigate the uncertainties. OH Logs, Wire Line Formation Tester (WFT) and test data from the studied and existing wells in the area were used to design the well test and interference with first appraisal well in an evolving situation, which is not typically faced in well operations. Hence, the results obtained provide an additional information that helped to conclude variable fluid distribution and its dynamic connectivity to the first appraisal well. Well was completed followed by test as designed and Production Logging Testing (PLT) was conducted to define reservoir contribution. Post well test analysis and comparison with existing WFT and test data from existing well helped to conclude results and address the uncertainties. This paper summarizes the design process, challenges faced in an unexpected variable fluid distribution in the horizontal section and accordingly how well test analysis was performed to conclude the results that helped to take optimal investment decision for the development of this marginal reservoir.

The objective of this paper is to share the experience of first worldwide job where wireline conveyed robotic cleaning tool was utilized to clean the obstruction in open hole section of oil well while collecting of uncontaminated sample of blockage material. Wireline conveyed, lightweight, robotic intervention tools were used in one of fields in Saudi Arabia to collect uncontaminated sample of obstructive material for future chemical treatment and to remove the bridge in Open Hole section of oil well, so Workover Rig or Coiled Tubing intervention can be avoided or significantly deferred. Operation was performed without killing the well and with no additional fluids pumped into well, reducing possible intrusion and skin build up. This technology was run first time in world practice to clear an obstruction in Open hole section. Severe planning was performed prior to technology introduction, including possible solutions comparisons and risk assessment. Robotic intervention was proven not only technically superior, but yielded large economic benefits compared to traditional descaling and sampling methods. It involved less personnel and produced much less CO2 footprint as well. Sample retrieved during the operation was analysed in laboratory and with high degree of certainty can be attributed as localized formation collapse. Same was confirmed by limited length of blockage that was successfully removed. This represented additional mechanism of wellbore restriction in the field. The experience from first worldwide operation, the methods and tools descriptions, process, lessons learned, recommendations and way forward will be presented in this work and should be of great interest for wide group of practicing engineers.

This well was drilled with the objective to support the pressure sustainability of multiple producer wells across Lukhweir-2 formation based on ERD approach. This paper presents the challenges faced in planning and drilling of subject ERD well with a total measured depth of 27,352ft (8.34km) and having horizontal hole of 11,300ft (3.45 km reservoir contact) with directional difficulty index (DDI) of 7.208 using light/slim casing design. Planning of this well started by meetings and collaboration with asset team to a common objective of delivering the longest well across Lukhweir-2 (LK-2) reservoir to support the multiple producers and mitigate all the associated risk by proper planning and drillability analysis such as trajectory design, collision risks, BHA, hydraulics and casing designing. This paper will explain the novel approach of mitigating the challenges faced while drilling this ERD well such as concerns about surface hole drilling (30 deg across interbedded shale formation), challenge in running 7" long liner (>8000ft across multiple reservoir) and overcoming surface pressure and torque limitations while drilling. Results, Observations, This ERD WAG injector well is the first and longest to be drilled with 6" drainage across Lukhwair-2 reservoir from artificial island to have 11,300ft of 6" Geo-Steered Horizontal hole section using Slim Casing design which gives the total well measured depth of well 27,352ft MD / 10,101ft TVD (2.7 ERD H:V ratio) Results from this well have proven that ERD wells with longer reservoir contact have significantly improved well performance, enhanced reservoir management and reduced field development cost. This paper summarizes the practice and technology used to drill successfully the longest ERD / MRC well using slim design practice which includes the utilization of special dope for 4" DP to increase the torque limit, use of special surface equipment called chillers/coolers to over overcome high downhole temperature. This paper will also capture the drivers, selection criteria and lessons-learned over the entire well drilling. The challenges/mitigation explained in this paper will stretch the ERD/MRC boundaries and support engineers to design the complex 3D wells with slim/light casing design and can achieve extended targets with 100% integrity.

Extended reach drilling (ERD) wells involves numerous drilling challenges that in many cases causes cost overrun and delays for such wells. This paper presents a new approach used to drill a 10,000 ft long departure using a slim design to replace the conventionally well design that uses heavy casings. This approach eliminated the 22" hole section and the associated 18 5/8" casing reducing 20 days form the well duration and saving $1 million. Achieving such a long departure requires a shallower kick off and requires building inclination as early as possible crossing reactive shales and need high mud weight to guarantee hole stability. Historically an additional casing string used in order to isolate a loss zone prior to the shale formation to drill it with high mud weight. This approach limited the inclination across shales and penetrated it along with the loss zone in same section by controlling the WBM weight to be just high enough for bore stability and minimizing the loss rate but increasing the challenges in the next sections. Drilling the single horizontal oil producer well started with a 16" hole size, kicked off at 300 ft and built to 22-degree inclination in that section and isolated with 13-3/8" surface casing. A 12-1/4" hole was drilled across the loss zone and reactive shales formation keep the WBM weight as 9.4 ppg (70 PCF) while drilling the loss zone and increased later to 9.9 ppg (74 pcf) prior to drilling the reactive shale where the inclination was limited to 27 degree across it and built later to 32 deg at the end of 12 ¼" hole section and isolated with 9-5/8" production casing.8 ½" hole section was drilled with 12.3 ppg (92 pcf) OBM in order to built 82 deg before penetrating the reactive shale and hold it tangent to cover the maximum departure and built to 90 deg to land in target reservoir with total departure of 10,755 ft and isolated with 8,150 ft long 7" production liner, followed by 4,000 ft 6‘‘ horizontal open hole. This novel light casing design avoided drilling a hole section of 22‘’ and the associated 18-5/8" casing, saving at least 20 days in well duration and nearly $1 million in well cost. The new slim well design explained in this paper, which is used to drill long departure well with 10,000 ft, is the first of its kind in ADNOC Onshore field. It has proved that such long departure wells can be completed with light casing design and achieve 100% integrity.

The paper describes the planning and design of the first pilot well to unlock tight oil from a heterogeneous Jurassic carbonate reservoir, offshore Abu Dhabi. Reservoir permeability ranges from 0.1 to 5mD, with more than 80% of oil in-place locked up in the 0.1-0.3mD rocks. Conventional perforation, acid stimulation and zonal tests were seen to result in unsustainable flow and very low productivity index. Prior to committing capital investment, a decision was made to screen different completion and production technologies to exploit tight reservoirs, and deploy a pilot well to assess the feasibility of commercial recovery. The pilot study addressed the full value chain of upstream oil development, from static and dynamic modeling, drilling, completion and stimulation strategy, geomechanics and technology options screening including assessment of subsurface uncertainties, material requirements, and economics. Several well construction, stimulation and completion options were screened including stair-step horizontals, multilaterals, fishbone wells, multistage hydraulic fracking, stem tunneling and fishbone stimulation. Multistage acid frac was found to be technically and economically feasible offering improved recovery. Furthermore, this option is Abu Dhabi’s first ever offshore multi stage acid frac pilot, which is expected to lead and potentially unlock the rest of offshore tight reservoirs across the ADNOC Group.

For the past few years ADNOC has extensively ramped up its effort in exploring and testing unconventional reservoir across Abu Dhabi tight oil and shale gas formation as part of its oil & gas 2030 strategy. Shilaif tight oil exploration started over 5 years ago with multiple vertical wells drilled and tested allowing discovery of stacked tight oil play with significant resources in place. To unlock these resources, horizontal drilling and multistage fracturing were used to confirm recoverable resources, and well potential. Prolific production results have since propelled hydraulic fracturing, hence it has become imperative to build a process to standardize unconventional fracturing technical and operational requirements and to maximize efficiency and benefit. A prime example of such process was in Huwaila-68 where the organic-rich Shilaif shale/tight oil formation was targeted. A target that is analogous to the Eagle Ford from the same Late Cretaceous age. A significant weight is put on reservoir quality assessment to minimize margin of error and increase the probability of fracturing success, and to maximize recovery of the estimated tight oil and shale gas in place. This process assessed the Shilaif from a geological, petrophysical, and geomechanical perspectives. This was followed by setting up preferential staging and perforation placement strategy for fracturing based on reservoir and completion quality which correlated to an initially built 1D mechanical earth model. Production forecasting using reservoir simulations were also utilized to assess fracturing success and deliverability. The processes above led to completing multistage fracturing in Huwaila-68 within the Shilaif formation by means of a pump- down perf and plug operation coupled with high rate slick water pumping, which was followed by extensive well testing. Operational efficiency allowed for the completion of 27 stages placing in excess of 7.3 million lbs of proppant. The use of chemical tracers as a qualitative measure allowed for correlation between natural fracture presence, recorded pumping events, and initially recorded gas shows while drilling. Such observations would help in well placement for future horizontal wells. Post fracturing production rates have met expectations, and were in line with the initial reservoir assessment predictions. The novelty of this paper is the inclusion of several domains to reduce the error margin of fracturing unconventional formations such as the Shilaif. Being an area where field development is rapidly taking place, the inclusion of new technologies have become persistent, and these were evident from the reservoir assessment phase, through to the fracturing phase, and ending with the well testing phase. This level of data gathering and assessment will act as a benchmark for all future unconventional fracturing within the UAE while lessons learnt will further enhance the turnover from drilling to production.

In the subject reservoir, geological features (high perm streaks and fractures) are the key performance drivers that affect injected water movement behavior. However the horizontal and vertical distribution of these features have high uncertainties and it is very challenging to accurately capture these features and map into model. Here we developed one workflow to capture these features by integrating different sources of solid data, from core, open-hole resistivity log, PLT, well testing, production and surveillance data, etc. This reservoir has been on production for decades and plenty of static and dynamic data were acquired for the whole field. Among those data, conventional core analysis (CCAL), log derived k-PHIE regression, and well testing will measure reservoir permeability values, which could give guidance to the areal distribution of high perm and low perm regions. Afterwards, the difference between well test interpreted perm and CCAL measured perm could give some indication of some geological features (HKS, fractures, etc.) existing or not. Furthermore, these geological features could be further confirmed by the dynamic data, such as open-hole resistivity logs, PLT, and well production performance data, etc. After confirmation, those preliminary geological features will be mapped into static and simulation models, and the seamless geo-engineering loop of history match process will proceed until the final history match stage without compromising geologic plausibility and consistency. Going through the above integration workflow, the history match process was completed and the final history matched simulation model gives very promising water saturation match quality in both horizontal and vertical directions. In the horizontal direction, ∼90% of the producers get water cut match (trend and magnitude, dWC<5%), and also for recent drilled long horizontal producers (maximum reservoir contact (MRC) wells), model production profiles and water entry points along the laterals have good alignment with PLT and open-hole resistivity log data. In the vertical direction, model water saturation profiles have good alignment with open-hole resistivity log trend for hundreds of wells (∼90% matched). PLT and WFL also have very good match quality. In general this simulation model could reproduce water movement very well in three dimensions using this new integration workflow, with much improvement compared to current the model. It gives higher confidence in the model predictive capacity, and the future field development plan will be studied using this New Generation Model Based on this integrated approach, a more plausible and consistent set of geological features are mapped and thus achieve promising history match quality of water movement with minimum local modifications, and thus enhance the model predictive capacity and provide better support of the life cycle field development.

This paper discusses how an organophilic clay-free invert emulsion reservoir drill-in fluid (OCF-IEF-RDF) was customized to successfully break the longest well record in the Middle East and North Africa region and the 4th longest extended-reach drilling (ERD) well globally. The successful design included extensive lab testing to optimize performance of this innovative low-solids OCF-IEF-RDF used to drill the 25,415 ft. horizontal reservoir section. This specially designed drill-in fluid reduced key risks for drilling ERD-type wells and kept parameters within necessary specifications to set new limits for drilling performance, maximizing horizontal section displacement/reservoir drainage, and production output. Challenges and risks related to drilling extended-reach wells require particular focus on the drilling fluid design in order to meet these challenges and to mitigate the risks. In addition, proper planning beforehand, and close monitoring and control of many fundamentally important parameters when drilling are required in order to execute successfully the drilling and completion phases for such wells. While evaluating the feasibility of drilling this well, establishing appropriate fluid system properties was a key focus area. The rheology profile was optimized for hydraulic management, hole cleaning, and fluid stability, and the ground marble bridging package was designed for minimum damage to the reservoir. Lubricity and rate of penetration (ROP) maximization were addressed by designing a low-solids OCF-IEF-RDF where the base brine was calcium bromide. The paper shall discuss both the processes used during the planning phase, including laboratory testing and hydraulic simulations, and the procedures followed during the execution phase, and how they helped ensure trouble-free performance during drilling. Proper planning and execution, using best-available drilling practices, enabled drilling of this record-breaking well without encountering significant issues that could impact rig time and increase costs. Selection of an OCF-IEF-RDF to provide low Equivalent Circulating Density (ECD) performance in a fragile gel fluid with low sag risk was fundamental to achieving required fluid properties. The low-solids design improved ease of deployment of the weighting material (ground marble) compared to similar fields where more conventional organophilic clay-based fluids are used. More than 25,415 ft. were drilled in 9 days with an average ROP of 216.8 ft. /hr. and 216.6 Rotating Hours and the best 8.5" daily footage of 4,121 ft. in the field. This resulted in the completion of the drilling operations ahead of schedule. This well is the longest single deployment production liner globally – 25,637 ft. and 4th Longest well drilled globally and longest well drilled in Middle east. In addition, production rate was as expected, confirming the anticipated non-damaging property of this OCF-IEF-RDF. The OCF-IEF-RDF was specially designed to deliver down-hole properties and behaviors that would deliver low ECD to Equivalent Static Density (ESD) margins. Without this superior control over ECD, the milestones above would not have been possible. It brought innovation to reality, which maximized returns by accessing reserves not easily accessible with conventional mud systems, drilling techniques, and saved on infrastructure costs. This increased reservoir drainage and resulted in significant productivity gains. Pushing the limit of this challenging condition can continue to break records in the future.

Water injection using horizontal wells has started since 2012 in North Kuwait carbonate reservoirs. The objective of this work is to integrate a detailed steady-state single well model with a dynamic reservoir model along to improve the permeability distribution inside the dynamic model along the horizontal section of the well. The workflow starts first by building a well model and quantifying the injectivity profile along the horizontal section from the actual wellhead injection pressure and dynamic reservoir parameters. Then the ILT (Injection Logging Tool) data is used by the well modeling simulator to calculate permeability distribution along the horizontal section of the well resulting in the measured outflow profile. The final step is to export the permeability multipliers along the open hole horizontal section of the well into the dynamic model to improve the dynamic model results at the well level. This workflow was examined on one injection well from the North Kuwait Carbonate formation and shows improvement in well bottom hole injection pressure, reservoir pressure, well injectivity index and water injection rates distribution along the horizontal Openhole section from the dynamic model and better history match. The coupling of a single-well advanced ILT interpretation with the field-scale dynamic model is considered as a novel approach that improves the dynamic modeling construction on a well-scale level. Instead of a classical approach where reservoir properties are used only to calculate outflow into the well an inverse problem is solved: calculate reservoir properties from a measured outflow profile.

The challenges of high heterogeneous multi-layer reservoirs were a driver for ADNOC to establish new well completion requirements. Based on this, the well completion strategy was revised in order to improve the completion design for a Dual Oil Producer (DOP) initially well planned without accessibility into the upper drain. The solution was successfully implemented by drilling the well having a Multilateral Dual String Level 5 Completion System to have full reservoir isolation and mechanical accessibility to TD in both drains. A major approach was implemented 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 the upper drain liner and for different completion runs. Thus, a level 5 multi-lateral completion coupled with Inflow Control Devices and Pre-perforated Liner in the upper and lower lateral respectively was successfully deployed. The main advantages of this technology compared to the initial proposal are: Brings effectively two single wells from one slot of the wellhead tower as it provides independent access & control for enhanced reservoir management (well stimulation, production logging and water shut-off). Substantial cost savings due to the utilization of one slot only. Conventional single designs need two slots to deliver equivalent completion requirements. The completion technology meets the Well Integrity Policy & Completion Guidelines stated by ADNOC to have full accessibility to all drains. This is the first Level 5 configuration installed in UAE integrated with a lower completion. The design enhances the benefits of the multilateral construction by providing full mechanical & pressure isolation at the junction throughout the life of the well. Furthermore, accessibility to both laterals from surface without the use of a re-entry deflector or any constraints was deemed to be paramount for a successful well construction.