Abstract Sand production in unconsolidated formations during sampling can lead to poor quality of samples being acquired due to plugging of flow lines and sealing issues at the probe. Formation pressure and mobility measurements can also be affected by sand production which may cause plugging inside the tool or at the tool inlet and result in increased operational time. Predicting sanding potential thus becomes critical to achieve both operational and formation characterization objectives, especially in deep-water environments, where operation costs are high. Calculating "Critical Draw Down" (CDD) pressure and predicting the sanding envelope through geomechanical-sanding analysis provide insights critical to successful testing and sampling operation. A fit for purpose geomechanical model has been developed based on petrophysical data along with regional knowledge of geomechanical conditions. With the geomechanical model, analytical sanding evaluation is used to calculate a range of CDD values for the likely testing and sampling points using well logs from offset wells. Logs from the studied well are analyzed in real time to update CDDs. The zones least prone to sand production are identified and prioritized for testing and sampling. The pre-drill sanding risk assessment is also used to optimize operational parameters including selection of the best pump and packer types while the real time updated CDD values is incorporated to limit the flowing (drawdown) pressures during the sampling and testing operations. A case study from a deep-water field in India is highlighted where the mentioned workflow developed post logging for a pilot wellbore has helped to optimize decisions in real time during formation pressure testing and sampling in its sidetrack wellbore, thus adding value to reservoir characterization objectives and reducing nonproductive time (NPT). Based on the pre-drill sanding assessment, CDD was found to be in the range of 0 - 500 psi below the formation pore pressure in some of the sand bodies. Also, a large face packer was recommended to enhance sealing efficiency by increasing the contact area with the formation. Pump rate was regulated during pressure testing and sampling to ensure that the pressure never exceeded the pre-defined CDD values thus preventing sand production. Multiple fluid samples were collected successfully without any plugging. This integration of geomechanical assessment with operation contributed to 32% increase in success rate for good quality pressure testing and acquisition of representative samples in the sidetrack wellbore, benefitted from a systematic adaptation of pre-job assessment and real time optimizations compared to the pilot wellbore. The pre-drill petrophysical and geomechanical evaluations provide critical insights to assist in real time optimization of pressure testing and fluid sampling operations in unconsolidated reservoirs. Workflow presented in this paper has proven to be valuable in obtaining reliable formation pressure data and contamination-free formation fluid samples for accurate reservoir and fluid characterization in unconsolidated formations during wireline logging testing and sampling operations.

Abstract Rate of penetration (ROP) modeling is one of the most important objectives of any drilling program. Penetration model depends on different criteria such as mud weight (MW), weight on bit (WOB), rotary speed (N), and so forth. It is a complex process, because of the high number of variables and uncertainties. Different mathematical models and evaluation methods were developed to solve this problem but they were unable to attain desirable accuracy. Adaptive neuro-fuzzy inference systems (ANFIS) could be used in these cases to predict the rate of penetration. ANFIS is a combination of neural networks and fuzzy logic networks and could be used to create a robust ROP model. The objective of this study is to apply the ANFIS method and compare the modeling results with conventional artificial neural network models. ANFIS trains the model using a set amount of data and then validates it against random data to measure the error. Drill bit record from a certain field has been taken as training data and testing data for the program. The selection process uses the Sugeno model for generating the fuzzy model and the backpropagation and gradient descent method for recognizing the patterns. The data was normalized and sorted out to remove the incomplete values. Tests were done by applying 2 and 3 membership functions to a 4 input interface and a 5 input interface. The accuracy of the results depends on the numbers of inputs and membership functions. Each input was tested with different membership functions to test the data. The output generated from the training process showed that sigmoid function and Gaussian function with grid partitioning and linear output function yielded the best results for 4 and 5 inputs using 2 and 3 membership functions each. The training error recorded was about 3 percent with a checking error of 20 percent for most cases.

Abstract This paper present the successful deployment of the ultra-deep EM tool in a mature carbonate reservoirs to reduce the uncertainty associated with fluid movement for horizontal/ MRC well-placement optimization and enable precise geosteering to maintain distance from fluid boundaries and mapping of nearby reservoirs for future reservoir development. In addition, the EM tool can facilitate to optimise lower completion design liner (blank pipe length, PPL, ICD and swellable packer depth). The high heterogeneity of reservoir qualities increase uncertainty in fluid distribution and make drilling long horizontal, oil producer wells in offshore mature giant carbonate fields very challenging. The usual plan is to drill a pilot hole crossing the reservoir sections, evaluate log saturation, and then re-optimize horizontal sections accordingly. To study the possibility of eliminating pilot holes, an ultra-deep electromagnetic (EM) tool was deployed. The first objective was to detect reservoir boundaries and predict resistivity of the target before penetrating it (Geostopping). The second objective was to optimize the horizontal drain (Geosteering), and map resistivity of adjacent reservoirs for well completion and future well optimisation (Geomapping). Pre-well inversion modeling was conducted to optimize the spacing and firing frequency selection in order to facilitate early real-time geosteering and geostopping decisions. The plan was to run the ultra-deep resistivity tool in conjunction with shallow propagation resistivity and density-neutron porosity while drilling the 8½ in landing section. The objective was to be able to detect the lithology boundary early and predict the resistivity of the reservoir before penetrating, facilitating geostopping decisions. This would allow optimization of the horizontal section to geosteer the well in an oil-saturated layer 4-6 feet from top boundary while geomapping the surrounding reservoirs’ resistivity. The EM tool delivered accurate mapping of thin reservoir layers while drilling the 8½ in section, as well as enhanced mapping of low resistivity zones up to 85 feet true vertical thickness in a challenging low-resistivity environment. Comparison to recorded open-hole logs for validation showed good results, enabling identification of the optimal geostopping point in the 8½ in. section. The EM tool is able to save up to five rig days in the future by eliminating pilot holes. The 6 inch horizontal section was successfully geosteered and placed 4-6 feet from top boundary. The EM tool was able to map reservoir resistivity 30 feet TVD below the wellbore and the completion design was designed accordingly. Additionally, the EM inversion for the nearby reservoirs helped to modify the plans for nearby future wells.

Abstract In order to support a new strategy for the development of the Northern part of a large carbonate reservoir, a multi-disciplinary and comprehensive approach was implemented to resolve the subsurface and surface issues associated with execution of the strategy. The plan is to have a balanced well count per year, optimise the existing geological target in the development plan, propose and implement artificial lift requirement, firm up the need for future Pattern Water Injection schemes. Consequently, a large number of additional producers and injectors is required to be drilled within a highly congested surface and hence the need to embark on Pad drilling to overcome some of these challenges. Pioneering the On-pad drilling in the field enable to increase and sustain the oil production target rate planned in Q1-2021 in addition to convert the Reservoir Development scheme to pattern injection. In order to expedite a robust and effective planning process, a timely and coordinated reservoir monitoring plan was put together and executed to reduce risk of gas for the new wells. In stratigraphically complex areas, pilot holes were recommended to help place and optimize well trajectories in the horizontal section. Key wells were nominated as candidates for accelerated acquisition of pressure and saturation data as critical requirement to understand fluid movement and consequently de-risk new target for the PAD wells. A drilling optimisation exercise which include the following ■ Mapping the target azimuth to the Plat Orientation for ease of drilling ■ Designed wells trajectories with long departure & high turn. ■ Rigorous anti-collision analysis. Very Difficult but detailed well planning process. Wells in area of moderate- high Gas/Water Saturation. ■ Utilisation of advanced completion technology to mitigate unwanted gas & water production. ■ Timely delivery of drilling proposals ■ The wells should be within the minimum recommended safety factor as per company drilling policy. The Cluster Drilling came into execution since January 2019. The main highlighted: ■ Well placement optimization for 24 on-pad drilling wells (8 platforms) by multidisciplinary subsurface integration. Should be available the Flexibility of shortening some wells H.H drain due to risk of high collision with existing wells. ■ Pioneering the On-pad drilling in the norther field successfully completing so far 3 Plats with 12 oil wells on sweet spots in 2019, estimating the associated oil potential in 24 MBPD. ■ Accommodated the required number of wells based on the company production target ahead of time, as per 2018-2023 business plan with the first well commissioning in Q1 2020. ■ To take maximum advantage, during PAD drilling planning process the reservoir monitoring plan should be prepared liaise with the underlying reservoirs, besides, with base on the new data findings allow to introduce changes at least in quarterly base ■ Cost saving was achieved by optimizing Gas Lift completions to 6 out of initially planned 12 wells based on simulation-surveillance integration work. ■ The Integrated Team organisation has worked well resulting in faster and higher quality deliverables

Abstract Many of the matured fields across the Middle East have formations with below-hydrostatic pressure, when drilling is completed without return to a surface. Most of the losses while drilling across vugular, fractured or weak formations happens suddenly, and a fluid level is not visible at the surface. Further the continuous mud cap is applied while drilling to maintain the constant bottom hole pressure. However, the mud cap flow rate and mud weight (MW) most of the time are based on local best practices and not supported by any engineering study, for example using 1.5 ppg at the rate of 1.5 BPM. To have a proper understanding of the fluid level the bottom hole assembly (BHA) is equipped with an equivalent static density (ESD) sensor was used. As continuous mud cap is required while drilling a special procedure was developed to allow tool application. This study was performed initially across the surface section (which together with an intermediate section often has losses in the Middle East), where based on offset well analysis a single lost circulation zone present and the chance of the well control is low. Based on the result of the study the fluid level was clearly identified. Further, to understand the effect of the mud cap flow rate the section was drilled by changing this parameter. The data obtained allowed to understand the effect of a flow rate on the fluid level in the annulus. Having this information the bottom hole pressure can be maintained with lower and constant mud cap flow rate, avoiding risk of wellbore instability or well control, as well as positive financial impact as expensive mud was not used at a high rate to top up the annulus. The obtained information and knowledge explore further the underground behavior of the depleted, fractured and vugular formations across the Middle East. The manuscript can be used by anyone across the world aiming to improve the service quality and reduce the cost related to mud cap as well as have better knowledge to present the well control risk.

Abstract Monitoring downhole drilling dynamics is an essential element to quality check the measurements provided in logging while drilling (LWD). LWD nuclear magnetic resonance (NMR) is sensitive to the motion induced from the bottom-hole assembly (BHA) during drilling, therefore, quantifying the motion effects becomes important to understand how to correct the measurements. Quantification and correction of lateral motion effects on NMR LWD are the objectives of this paper. Data was collected from various BHA combinations with LWD NMR to model the responses, which were compared with actual downhole conditions to assess the need for the lateral motion correction (LMC). Vibrational assessment criteria are utilized to assign a severity level, which dictates the level of the LMC. The LMC applies an algorithm to differentiate true formation signal responses from the vibration signal response. Specifically, the motion effect function was integrated into the forward matrix of the NMR joint inversion, and a nonlinear optimization algorithm was used to determine the four motion parameters, and if present, compensate for lateral motion effects. In wellbores with severe motion vibration there were large discrepancies between real-time and memory data, which resulted in mismatches with the measured partial porosities. Investigations were conducted on the BHA design, well trajectories, and wellbore environment to quantify the lateral motion effect on the NMR measurement. This information was then compiled to incorporate all aspects of BHA design techniques to mitigate the lateral motion effects on the NMR measurement. The LMC algorithm gives added confidence to ensure all data collected is consistent and reliable even in more challenging wellbore environments, which could be subjected to unanticipated lateral motion. This paper highlights an approach to integrate BHA simulation principles to anticipate severe motion effects during drilling. This knowledge, coupled with the LMC, creates a platform to enhance NMR data quality.

Abstract A large operator of a brown field offshore in the middle east has decided to provide full lower Completion accessibility and ensure prevention of open hole collapse as it can lead to various gains throughout the life of the well. Among those benefits, it provides a consolidated well bore for various production logging & stimulation tools to be deployed effectively, as well as full accessibility, conformance control and enable to provide production allocations for each zones. However there are multiple challenges in deploying lower completion liner in drains involving multiple reservoirs and geo steered wells: Well Bore Geometry, dog legs/ tortuosity etc. & differential sticking possibilities and of course the open hole friction. Due to the size of the open hole, restricted casing design and utilization of limited OD pipes further add to the complications of deploying the Lower completion liner in such brown Field wells. This paper intend to review the multi-step methodology approach implemented in recent years by the company to effectively deploy 4-1/2″ Liner in 6″ Horizontal Open Hole section. Among the techniques used to assist successful deployment of lower completions are: Improving hole cleaning, ensure smooth well bore with the use of directional drilling BHA, reduction of the Open Hole friction by utilizing Lubricated brines, fit for purpose Centralizers, use of drill pipe swivel devices to increase weight available to push the liner & reduce buckling tendency. With the length of open hole laterals reaching up to 10,000 ft for 6″ Lower drains, open hole drag, friction & cleanliness are major components that causes challenges in deploying the Liner till TD. The use of specially formulated brines with fixed percentage of lubricants proved to significant reduce friction compared to the drilling mud used for drilling the horizontal drain. The combination of low friction brine with proper centralization / standoff which resulted in reduced contact area with the formation has also shown good results in preventing differentials sticking while running the liner through multilayer reservoirs having significantly different reservoir pressures. Another major constrain to deploy the lower completion liner in this offshore field is the very nature of the wells being primarily workover. This involves generally Tie back liners run to shallow depths to restore the integrity of wells. This limits our ability in the selection of drill pipe that can be used as only smaller OD drill pipes and HWDP can be utilized in order to deploy the Liner to bottom. On many occasions this provides only limited weight to push the Liner down to TD and impact our ability to set the liner top packer. Drill pipe rotating swivel devices have been utilized to improve our weight availability & transferability to push the liner down and to set the liner top packers. In order to provide independent deactivation mechanism for the drill pipe swivel and to have complete success in our liner deployments, a dedicated ball activated sub was designed to deactivate the swivel acting as back up in case primary deactivation methods fails during liner setting. The combined use of all these techniques enabled the company to deploy 4.5″ Liners in 6″ Horizontal drains with high success in this offshore Brown Oil field of UAE. This resulted in better well construction and complete access to lower drains over the life of the wells.

Abstract Wellbore instability challenges encountered while drilling the Nahr Umr Shale include, but are not limited to, hole collapse leading to hole enlargement. Wellbore instability leads to huge cost increases in the drilling process and in rare cases well abandonment. Observations from drilling data suggest that wellbore stability varies with different wellbore deviations and azimuths, especially in areas of highly laminated formations and anisotropic in-situ field stresses. Accurate information on the rock strength and rock failure behavior in shale has a major impact on the improvement of drilling efficiency. Knowledge of the mechanical properties of shale is essential to implement any 3D shale anisotropy borehole instability model ( Crook AJL, et. al., 2002 ). Shale mechanical properties were evaluated from laboratory tests. Well-preserved core samples retrieved from the Nahr Umr Shale were put through several tests to describe the mechanical characteristics related to rock strength and in-situ stresses with the aim to determine the effect of the anisotropy and plane of weakness in drilling high-sailing angle trajectories. Strength anisotropy was assessed using the plane of weakness model ( Jaeger, J.C., & Cook, N.G.W., 1979 ) which assumes that the heterogeneous media is composed of a matrix rock and a plane of weakness (e.g., bedding/laminations, interface between lithotypes or laminations). Shear failure occurs once the shear stress acting on the plane of weakness exceeds its shear strength. Laboratory tests include both extremely slow triaxial tests and multistress path testing performed on three orientations. Failure envelopes were created to develop the plane of weakness model to predict the orientation of the weakest plane and determine the magnitude of the strength reduction. Elastic anisotropy data from plugs is combined with advanced sonic logs, enabling a more robust evaluation of the formation anisotropy to improve both stress predictions and the allowable mud-weight windows during wellbore stability assessment.

Abstract Here we present commercialization and mechanisms to manufacture bulk-metallic-glass composite (BMGC) dissolvable plugged nozzle assemblies (DPNA) for injection wells in offshore Arabian Gulf. These DPNAs' are to be installed on limited entry perforated liners for an extended performance, providing significant cost benefits to operators. While elastomeric plugs have significant shortcomings, thermal stability, extrudability among others, as such compromised high temperature performance, our metallic dissolvable alloy has reliable performance at elevated temperatures even at higher pressures. Our article encompasses design, verification and validation (V&V) data for a nozzle with a partially vitrified, nano-metallic dissolvable plug to withstand 3,500 psi differential pressure across the nozzle, where (i) Ability of DPNA to hold pressure between 12 and 36-hour (0.5 to 1.5 days) when pressurized from ID to OD, with subsequent breakthrough on pressure reversal of 200 to 500 psi (OD to ID) within 14 days from start of operations (ii) Environment encompasses up to 43% Bromide salts as completions brine to prevent deposition of Ca 2 + ions abundant in Middle East and North Africa (MENA region) or up to 21% Chloride salts (iii) Temperatures as high as 200 ºF, will be a first of its kind. V&V is supported by flow testing combined with CFD performed on potted DPNAs'.

Abstract 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.

Abstract 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.

Abstract Drilling tools are subjected to mechanical loads while drilling, resulting in loss of performance due to accelerated wear and subsequent tool damage. Two special phenomena are well known to generate high mechanical loads in torsional direction: Stick-Slip and High Frequency Torsional Oscillations (HFTO). Preceeding studies have explained the nature of the interaction of these phenomena, how they can superimpose and how stability maps define safe combinations of operational parameters. This paper will provide a systematic and quantitative study of these effects based on high-frequency measurements recorded during a North Sea deployment. In this paper, for the first time, an in-bit high frequency measuring device is used to validate the theoretical modeling of the stick-slip-HFTO interaction. Field data from the North Sea including surface and MWD measurements are used in a broad study to investigate the influence of operational parameters, bit and formation on the torsional dynamics over the increasing depth of a well. Pure Stick-Slip, pure HFTO as well as the development of HFTO within a slip-phase of stick-slip is observed, described and compared to the theoretical model describing self-excitation. Several hundred instances of stick-slip are used to determine characteristic RPM thresholds for combinations of RPM and WOB. The totality of these thresholds compose a stability map indicating zones of reduced torsional loads. The study shows that stick-slip amplifies torsional loads generated by HFTO up to a certain RPM threshold. Further increasing the RPM leads to reduced loads for certain combinations of bit, formation and operational parameters. In contrast to common belief, higher RPM can lead to lower torsional loads in certain scenarios while also increasing ROP. The stability map summarizes the learnings, indicating zones of safe operation in an accessible manner. The resulting stability map can be used by operators to navigate in stable regimes of operational parameters. This reduces wear, tool damages and enhances drilling performance.

Abstract 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.

Abstract Recent development of horizontal well completions and stimulation methods enhanced the development of conventional and unconventional resources. Multistage fracturing allowed oil and gas operators to stimulate long laterals in continuous and efficient operations that increase the reservoir contact, thus increasing the recovery of oil and gas. Oil and gas operators work to improve the efficiency of multistage fracturing treatments by developing and integrating enabler hardware, processes and chemical technologies to enhance the fracturing operations and reduce cost. This paper reviews and discusses the different types of horizontal wells with multistage fracturing completions and stimulation techniques including plug-and-perf, abrasive jetting, just-in-time perforation, sliding sleeve systems, coiled-tubing conveyed fracturing systems and annular isolation methods. The efficiency of the multistage fracturing treatments depends on multiple factors comprising the operational time and cost associated with different type of completions such as plugs and sleeves, different intervention operations such as wireline or coiled-tubing and different stage distribution and pumping designs. Combination of multiple multistage fracturing methods resulted in hybrid cost-effective treatments. In addition, multistage fracturing fluids diversions contribute significantly to the stimulation efficiency. Different types of diversion methods are discussed for each stimulation system. This paper provides a comprehensive summary of the operational practices, fracturing methods, and different multistage fracturing completions in horizontal wells while emphasizing on the recent advancements available in the market. The ability to develop an efficient and effective multistage fracturing operation is based on understanding the reservoir requirements, and identifying logistical and resource challenges at the geological location where the operation is taking place. The developed solutions would be an integration of currently available process, with proper completions, materials and development of innovative enabler technologies to accomplish optimum procedures. In recent years, several enabler technologies were developed to address the challenges within the existing multistage fracturing operations. The electronic monobore sliding sleeve was developed to address the limitation caused by small ball seat (baffle) in ball actuated sliding sleeve completions. Plug-and-perf operation was enhanced by applying the Just-In Time Perforation (JITP) method by developing a new perforation gun assembly that cuts operation time. Development of autonomous completion elements with the ability to navigate and self-destruct after accomplishing the job helped to reduce the number of trips into the well that greatly affected the operation efficiency. Completion elements and diverters built from dissolvable materials eliminated the drill-out and cleanout operations, which reflect positively on the efficiency of the fracturing process. Reviewing current advancements of multistage fracturing completions and treatments can pave the way for further operation optimization and cost reduction.

Abstract Introduaction In a newly discovered field in the south east of Abu Dhabi, ten Thammama reservoirs were penetrated using a single well and how accurate an understanding of a reservoir and the uncertainties remaining can be assessed by a single well penetrating an accumulation of Hydrocarbon is a frequent question for companies planning to develop new, small reservoirs. The answer depends on how much data the single well got and the other information available about the reservoir and analogue reservoirs. When it comes to Modelling a reservoir that has only been pierced by one well, the assurance on the robustness of the available information is necessary in order to identify gaps and areas of uncertainty and then seek the means to minimize them. X-1 well drilled at the Crest of the structure and the location defined by utilizing leatest 3D seismic cube and the total depth 11500 ft RTKB. It was penetrated in the Lower Cretaceous sequence including ten reservoirs which are trapped by 4way dip closure. All the main reservoirs were tested in X-1 well and produced with an oil rate of 370 - 4,370 BOPD (30° - 32° API) An analytical "Lambda" Saturation Height Function was developed and implemented in order to overcome the absence of MICP data for initialization stage of Dynamic Modelling. Numerous choices made to develop a family of models that represents the range of reservoir possibilities. Uncertainty analysis including Analog Data from nearby fields utilized to rank the range of outcomes and prioritize obtaining additional information. This paper highlight a case study of a three onshore Abu Dhabi discovered structures addressing mitigations toward the challenges to draw a solid conclusion with single well modelling when it comes for development decision by Stakeholders at later stage. Further, the methodology as applied to the case study in this paper, allows identification of the range of outcomes and ranks the additional requirements, ranging from acquiring new Seismic data to drilling new wells, which guide for the next steps to a management decision to develop the reservoir or not.

Abstract The current radial well operation technology can not adapt to high temperature, and the long tripping period and low drilling efficiency in deep well conditions.According to the characteristics of abrasive jet, a new radial drilling method is proposed in this paper, in which the abrasive jet is conveyed to the underground by CT (coiled tubing), the casing is sidetracked first, and then the formation is drilled. The working procedure is that using the CT to run the positioning and guiding tool in hole first, and then using the CT to run a steel tube in hole. When the steel tube reaches the deflector, it makes a radial turn, and the ground equipment transfers the abrasive drilling fluid to down hole through the CT. During the operation, the casing sidetracking is completed with drilling fluid with high abrasive concentration, then the abrasive concentration is reduced, and the steel tube enters the formation to complete the radial drilling. Practice has proved that when the well temperature exceeds 100°C the jet hose is easy to be damaged under high temperature and high pressure environment, resulting in leakage of drilling fluid and unable to complete the operation normally. It is necessary to select a suitable temperature-resistant jet hose. Practice has proved that when the well depth is more than 4000 meters, the pressure loss along the system increases and the jet water power from the nozzle decreases. For hard formation, the water jet is not enough for rock breaking drilling in the formation. The results show that under the same water power condition, abrasive jet has stronger ability to break rock and penetrate hard stratum than water jet because it contains solid particles with higher hardness and density. At the same time, the abrasive water jet with suitable abrasive concentration and water power can be used for casing sidetracking. The casing sidetracking and formation drilling are combined to simplify the process. Experiments show that the types of abrasives, abrasive concentration, drilling fluid composition, drilling fluid water power, injection time affect the casing window opening and formation drilling effect. The method introduced in this paper solves the technical problem of water jet radial drilling, which is easy to break jet hose at high temperature (180°C) and can not break rocks due to the decrease of water power in deep wells (4500 m), and expands the application scope of radial drilling technology. Secondly, it simplifies the working procedure and opens up a new construction technology.

Abstract A digital blowout prevention equipment (BOPE) pressure testing system was deployed on a remote land drilling rig in Argentina in October 2017 to replace the older testing method using an analog circular chart recorder. This paper presents a case study of that deployment, focusing on change management, cost savings, and overall BOPE testing improvement. Results from the deployment include a 50% reduction in BOPE test time with subsequent savings that amount to 6 times the cost of the digital test equipment, improved safety, improved efficiency in addressing problems that would result in a failed test, improved data reliability, and repeatability in subsequent BOPE pressure tests.

Abstract This case study presents the challenges faced and learning curve built while achieving longer departures with light / slim casing design instead of conventional / heavier design in shallow coastal water field in UAE. This paper intends to explain the challenges that were encountered and the process of mapping the lessons learnt to ensure improvements along the process. The process involved the casing points analysis evaluating the competent formations options, continues optimization of well trajectory by increasing the inclination across problematic formations while drilling the intermediate section (limited in previous drilling campaign in the area), the evaluation of the impact caused in the consecutive 8 ½" phase (longer section), implementation of best practices to mitigate stability issues and Invisible Lost Time (ILT) methodology application to minimize hole exposure duration. The challenging campaign had the objective of saving cost by reducing one [FQ1] construction [FQ2] phase and continues achieving longer departures successfully which was a milestone during the well construction, thus a learning curve was built focused on continuous improvement of key operations. After completing more than 100 wells, the most beneficial point this change has offered is drilling long departure wells saving one phase in comparison with the conventional design in the area, which is the key element for cost reduction and also allowed to reduce crew exposure to heavier casing handling improving HSE risks. Currently, a maximum departure/vertical section of 10,700 feet has been achieved with light/slim casing design. Overall duration saving is 16 days compared with the best heavy casing design duration and 20 days with average heavy casing design duration with 35% saving duration. Drilling light casing design instead of conventional heavy casing design enable average of USD 2 million saving per well. The consolidated experience built throughout planning and execution since the first well, enabled an important performance improvement based on the learning curve built along the years. Nowadays, many fields require drilling wells with long vertical section / departures to reach further targets, away from the feasible surface locations. Additionally, cost reduction is another concern due to Oil Market fluctuation by applying new strategies and optimizing the performance without jeopardizing but improving the HSE at the same time. This paper presents a novel approach to well construction by showing the lesson learn that allowed well duration reduction, drilling more wells per year and consequently bringing early production, increasing efficiency and significantly reducing cost, therefore increasing productivity and profitability, at the time of contributing to HSE improvement.

Abstract Cementing of production casing in the Northern Iraq poses challenges to the cement sheath integrity due to mechanical and thermal stresses induced in the well life. The problem is further aggravated due to narrow window between pore pressure and fracture gradient. The acid-prohibitive cement system with improved mechanical properties was developed to mitigate the effect of induced stresses. The job was executed with operational optimization and zonal isolation was achieved. Based on the operator's well testing and multi-stage high-rate well stimulation plan, the stress modeling was carried out to determine the optimum mechanical properties. The 19.6 ppg heavyweight cement system with a flexible thermoplastic polymer was designed to achieve the required Young's modulus and Poisson's ratio. Since the density and friction pressure hierarchy could not be met due to the narrow window between pore pressure and fracture gradient, therefore, the slurry rheological properties were optimized for effective mud removal. The pumping parameters were adjusted to maintain the primary well control during the cementing operation without compromising displacement efficiency. The approach was implemented without any operational issues in the 9-7/8" production casing and 7" liner cementing. Following the job completion and waiting-on-cement time, the 9-7/8" casing was successfully pressure tested with a surface applied pressure of 2,000 psi and a well fluid of 1.78 SG. The isolation scanner cement evaluation confirmed the zonal isolation along the open hole of both the 9-7/8" intermediate casing and the 4½" production liner. Finally, the multi-stage high-pressure stimulation operations were performed during the completion/testing stage with no sign of communication between the different zones. The application of heavyweight acid prohibitive flexible slurry helped the operator to isolate the different zones of interest that were less than 10 m apart and retained the integrity of the seal throughout the high-pressure stimulation operation. Well is open to production without any annular pressure, thus, saving the operator's time and cost on the remedial cementing operations. The proposed solution will help operators to ensure long-term zonal isolation in the HTHP wells which are subjected to dynamic pressure and temperature changes in the post slurry placement phase. The operators can also avoid the time and money on expensive remedial operations.

Abstract Prevention of workplace accidents remains a challenge to the Oil and Gas industry to avoid interruptions to business, safeguarding their employees and maintaining their reputation. The Oil and Gas Industry is challenged by repetition of incidents, despite addressing root causes of incidents. Typically incident investigations highlight gaps in the implementation of an HSE Management System and often corrective actions include revision of procedures, more training, enhancements in work planning, design review and procurement of new tools. Analysis of over 500 Oil & Gas incidents investigation was carried and the repetition of incidents was noted despite addressing the identified gaps and further linkage of human factors with causes and corrective actions was further analysed. An analysis of findings and causes of incidents was carried out and human factors such as incorrect decision, improperly performed action, improper lack of action and presence of error inducing precursors were re-mapped to assess effectives of the investigations. It indicated that over 80% of drilling incidents were due to human factors and the following were the repetitive human factors issues leading to majority of incidents: Work load and task decision Motivation and attention Competence and learning Communication Remapping of conventional causes with human factors guidelines, highlighted consistent patterns of causation of incidents where multiple human factors criteria were formerly overlooked, led to these losses. Based on the analysis, the incident investigation training curriculum was revised to include human factors and error recovery, which was often, if not totally overlooked, was identified as a theme for corrective actions. It was noted that corrective actions (75%) were ineffective, as those actions were not directed toward human factors. It has prompted organizations to change the way incidents were investigated and the need of linking system causes with specific human factors deficiencies. It was found that 80% of drilling related incidents within ADNOC were triggered by unsafe actions and 62% of unsafe actions were due to human error & mistakes and 40% of drilling incidents were triggered by inattention/lack of awareness/unintentional human errors and violations by individuals, supervisors and by the group amounted to 15% of all immediate causes; and ack of knowledge of hazards present accounted for 14% of all immediate causes. Inadequate Identification of Worksite/Job Hazards accounted for 13% of overall drilling incident root causes and root causes associated with Human Factors contributed to 50% of all drilling incidents. This approach has led to changes in incident investigation curriculum in areas such as interviewing witnesses, identification of errors and identification of corrective actions. List of incident causes has been disintegrated to focus on type of error and error inducing factors. This novel approach focused on causes and provided efficient corrective actions to avoid recurrence of incidents. Analysis indicated that employee's low risk perception was due to lack identification of work site/job hazards followed by lack of leadership were the predominant root causes of incidents.