Abstract This paper discusses a new technology that helps to identify and differentiate multiple downhole well integrity events - tubing leaks, casing leaks, flow behind casing and overburden integrity, using unique algorithmic pattern recognition capability based on acoustic measurements from Distributed Acoustic Sensing (DAS) data. Here, we demonstrate application of this technology to identify flow behind casing and effectively build remediation strategies for Plug and Abandonment (P&A) of one of the wells in a BP operated field. Applying DAS for tubing leak detection has been discussed in prior publications. The approach has however, relied on simple data processing methods ‘listening’ for zones of increased noise when wells are shut in. In this paper, we discuss results from the application of a novel real time pattern recognition based approach to processing data from DAS that: Denoises data to decouple fluid movement ‘signals’ from background noise Uses signature recognition to constructs fluid ‘flow logs’ across the entire length of the well bore every second; Displays evolution of the fluid noise through depth and time The technology has been deployed across several assets for identifying well integrity events through different stages of well life – starting from drilling, production through to abandonment. In this paper, we demonstrate the application of the new capability for identifying flow behind multiple casing strings on one of the BP operated wells. The system was deployed to identify and pattern the evolution of fluid movement noise behind multiple casing strings through time and depth which was then used in conjunction with a tailored operational workflow to inform effective remediation strategies for plug and abandonment of the well. The fluid flow logs generated were used to conclude on the source of flow, flow propagation and pathway and facilitated an informed decision on extending the well’s first lateral barrier into the formation and adjustment of the position of the planned second barrier. The results showed the effectiveness of the capability in the field and demonstrated its unparalleled value for the operator, allowing for well abandonment. The technology offers a new method of acoustic data processing on DAS that extracts valuable and often hidden insights to identify the source of fluid flow and flow pathways, providing an ability of capturing events behind multiple casing strings – all fundamental challenges that the industry has been looking to solve for several decades.

Abstract Wrench fault system is the predominant regime of Abu Dhabi tectonics and their related damage zones influences the stresses between the fault segments and hence representing the main controlling factors in field development of hydrocarbon. The strike-slip structures are related to the activation of sinistral strike-slip shear zones oriented N75°W, which initially inherited in the Arabian Plate craton and activated trough the geologic time. The main reactivation happened with the Late Jurassic- Middle Cretaceous and then by the Paleocene and finally by Late Miocene. These reactivations accompanied with block rotation of the stress tensors from NE-SW to NW-SE and finally by NE-SW respectively. The identification of transpressive and transtensional structures are the main concept of locating the hydrocarbon provinces. During the transpressive stage, sinistral transcurrent movements along the Abu Dhabi Shear Zones led to the activation of a multiple set of parallel sinistral faults, conjugate and antithetic to the master fault. The activation of these structures determined a deformation by block rotation that provoked an overall anticlockwise rotation of (N150° to N120°) of 30°. The data show how the rotations occurred might be caused by the activation of multiple strike-slip fault sets and that the rotational mechanism around vertical axes is connected to transpressive tectonics. The use of kinematic and geomechanical models allow quantification of the blocks rotation due to the combined action of multiple sets of strike-slip faults with modest displacements and to demonstrate that the rotation of blocks and their lateral movement constitute two different, contemporaneous expressions of a single deformational event. A systematic classification of the rotational zones and their influences on reservoir behavior was addressed. Classification of stressed zones favoring reactivation based on their location relative to fault segments growth. Therefore, development of structures were combined with fluid flow in/between fault segments to characterize placing wells for an effective field development plan.

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 The objective of this study is to provide an overview of recent waterless stimulation focusing on hydraulic fracturing technologies, advantages and disadvantages, limitations, and new technologies under development. Different technologies are presented including proppant-free such as slurry fracturing and in-situ proppant generation, CO2, LPG, Seawater, plasma fracturing, high power lasers, gas stimulation, exothermic reactants, and high energy gas fracturing. Water-based hydraulic fracturing is commonly used stimulations to recover hydrocarbon specifically from the tight formation. The unconventional reservoir requires pumping and fracturing multistage to maximize stimulated reservoir volume. This technology involves the use of large volumes of high water quality, pumping at high pressure, and filling up the fractures with proppants. Several technologies are presented in an effort to find alternatives to current water-based fracturing technologies. The industry efforts towards waterless fracturing technology are to adapt different technologies into fracturing, for example, the use of plasma to create fractures. The principle of this technology is to store large electric charges and release them in a very short period. Another technology is based on gas combustion to create pressurized gas, which can then create fractures in the reservoir, the use of high-energy laser is used for fracture initiation, and in-situ proppants are targeting chemicals that generate proppant in the fractures. Jetting is also evaluated where acid is injected at a high rate for deeper penetration to create network tunnels. Exothermic fracturing is also discussed which is a technology based on chemical reactions that are triggered at downhole temperatures releasing pressurized gases and creating fractures. Once the drilling operations of a well are concluded, the well is then completed and stimulated. A typical scenario is to perforate the well using a shaped charge perforating gun followed by acid or hydraulic fracturing to maximize reservoir contact. A considerable reduction in permeability can occur when using conventional shaped charge gun, when the fracturing fluid formulation is not appropriately designed, or when improperly flowing back the fracturing fluids. A thorough investigation of recent non-damaging waterless stimulation technologies is included as an alternative to shaped charge gun perforation or to fracturing with water. If conventional fracturing is to be used regardless, then these technologies can be used to help initiate the fracture by lowering the formation breakdown pressure. In addition, it is possible to use these technologies in producing wells to enhance productivity. The discussion will provide details of each technology: suitable use scenario, methodology of use, limitations, and results of case studies. As more and more wells require stimulation to be produced commercially, new non-damaging waterless methods are implemented. The importance of this paper is to show these alternative technologies to increase production and minimize damage to reservoirs.

Abstract Shale rocks are rich in organic minerals, also it contains multi-scale micro-nano pores, making flow mechanism of fracturing fluid in microscopic pores of shale and the interactions between fracturing fluid and shale very complicated. In this study, firstly, the initial microscopic pore structure of shale before hydration was analyzed by field emission electron microscope. Secondly, the dynamic changes of microscopic pore structure in shale hydration was observed at fixed points with the scanning electron microscopy to find out the correlation between induced micro-fractures and mineral components. Finally, the influence of hydration on the changes of shale physical properties was analyzed. The test results of shale sample from Longmaxi formation (LF) in the Sichuan Basin indicate the micro-fractures induced by shale hydration weremainly shale bedding fractures, with obvious directionality. Clay minerals play a leading role in the formation and expansion of induced fractures. After 10 days of hydration, the porosity can be increased by 2.1 times, and the permeability can be increased by 273.7 times. Therefore, an appropriate shut-in treatment can dramatically enhance post-fracturing performance. The research results can guide the optimization of flowback system and provide scientific basis for efficient development of shale gas reservoirs.

Abstract The main objective of this paper is understanding the impact of the fractal characteristics of fractured reservoirs on their pressure behavior, flow rate decline, and productivity index. The paper aims to propose a new methodology for developing several analytical models that could be used for describing the wellbore pressure behaviors at a constant sandface flow rate and the flow rate decline trends at a constant wellbore pressure. Considering the fractal characteristics in the proposed analytical models may help eliminating significantly the uncertainties in predicting reservoir performance in highly disordered and heterogeneous formations. The target of this study is the reservoirs characterized by a complex structure and undergoing an anomalous diffusing flow mechanism such as naturally fractured reservoirs with a nonuniform distribution of embedded fractures and depleted by multiple hydraulic fractures. The proposed methodology considers including the fractal characteristics such as the mass fractal dimension, conductivity index of anomalous diffusion flow mechanism, fractal-network parameters, fractional-derivative order, and matrix/fracture-interaction index as well as dual-porosity media characteristics such as the storativity and interporosity flow coefficient in the analytical models of the pressure, rate, and productivity index. These analytical models are derived for the porous media with the fractal networks of fractures that are embedded in the matrix and connected to hydraulic fractures. The porous media in this study are represented by two volumes. The first is the stimulated reservoir volume with a rectangular-shape area of a length equal to the hydraulic fracture length, while the second is the unstimulated reservoir volume that extends away from the tips of hydraulic fractures towards the reservoir boundaries. The solutions of the two approaches of the inner wellbore conditions are demonstrated in this study. The first is the wellbore pressure drop assuming constant sandface flow rate while the second is the decline rate and cumulative production assuming constant wellbore pressure. The outcomes of this study are: 1) Understanding the impact of the fractal characteristics on pressure behavior, flow rate declining pattern, and productivity index scheme during early and late production time. 2) Developing analytical models that consider the fractal characteristics of structurally complex reservoirs depleted by multiple hydraulic fractures. 3) The study has found that some of the fractal characteristics such as mass fractal dimension has a significant impact on reservoir performance while others such as matrix/fracture interaction index may not have a significant impact. 4) Fractal reservoirs exhibit better performance than the standard geometry reservoirs of single porosity media or naturally fractured reservoir with dual-porosity media. The novel point presented in this study is developing a new methodology for including the impact of the fractal characteristics in the pressure, rate, and productivity index models. In these models, the stimulated reservoir volume is assumed as a vertical wellbore with an equivalent radius equal to the fracture half-length. This approach is verified by comparing the results of pressure, rate, and productivity index obtained for a very short fracture half-length with the result of the vertical wellbore wherein an excellent matching is observed.

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 The paper describes the execution of a successful rigless intervention solution deployed to establish well integrity and restore well production in a field in Europe. The paper will go through the planning and execution of the job highlighting the criticalities encountered and the overall benefit of the activity. The approach used was a deep analysis of the well integrity issue from several prospectives. A new opportunity in the production optimization fluid has been identified. After an open discussion between Customer and contractor, a customized blend and detailed pumping procedure was agreed upon to reach the final scope. An injectivity test was executed to align the procedure to the reservoir and well behavior. Several pressure tests were performed to confirm the remedial job in place, and, after that, the well was re-perforated and opened to the production. The horizontal well described in the paper, shut in during 2016 due to formation damage and depletion was selected for a new through tubing perforations interval by coiled tubing in the horizontal section. An unexpected firing head activation occurred at an unplanned depth, just above production packer. This event produced communication across the production tubing, liner, casing, and formation, which immediately induced total losses into the naturally fractured carbonate reservoir causing well control issues. The accidental perforations could have jeopardized the final scope of the project with no oil production and premature well abandonment. A successful rigless remedial intervention was immediately executed to restore well integrity by using a real time fiber optic coiled tubing acquisition and a new conformance fluid combined with a customized cement packer technique. The remedial intervention allowed the operator to resume the initial project's scope of opening the new perforation intervals, restoring an important oil production of about 150 [m3/d]. The final solution utilized a product with unique thixotropic properties which was then engineered for production optimization using a detailed pumping strategy. This novel approach added significant value, as the operator was able to restore the integrity of the well in rigless mode, avoiding the associated rig cost.

Abstract The paper describes the use of new generation of inflow chemical tracer application at Salym Petroleum Development Upper-Salym oilfield as a part of Smart Field project. This kind of well surveying using indicators that allow the evaluation of the inflow composition for each hydraulic fracturing port in horizontal wells remotely, without any additional risky and costly downhole activities. The new inflow chemical tracer technology is based on the use of nano-particle quantum dots, which give a level of high accuracy in quantitative analysis of fluid inflow. Markers, which are micromillimeter in size, are inserted into the polymer coating of the proppant. The technology involves the injection of marked polymer-coated proppant in the process of MHF (multi-stage hydraulic fracturing). Once the MHF is done, and the well is producing, the fluid samples are taken at surface and tested in a laboratory using machine learning software. Once the obtained data is interpreted, a flow profile of oil and water can be generated for each frac stage. One of the main advantages of marker technologies is that they provide data over a long period of time, with a significant reduction in operating cost. It opens the door for new opportunities in terms of more accurate reservoir characterization and better hydrocarbon recovery. The key element of the technology is the use of specialized intelligent machine-learning software based on Random Forest algorithm to produce production flow profile. The described methodology was used during the multi-stage hydraulic fracturing operation on oil wells 8105 and 8064 of Upper-Salym field. The volume of proppant injection at each stage was 20 tons, out of which 15 tons were of marked proppant containing a unique code for each stage. As soon as marked proppant has a contact with well fluid markers are emitted into fluid and sampling at the wellhead can be done any time when information required. The results of samples analysis are reports with graph showing quantitative distribution of water and oil production of each fracturing interval. The new generation of inflow markers allows for continuous production, surveillance and quantitative analysis of oil and water phase from each fracturing stage. This enables better decision making to optimize the production and make better decisions for water conformance interventions. This surveillance method does not require complex and risky well interventions or production shutdowns, making it substantially more cost effective than the existing conventional methods. Optimization of oil production, remote monitoring for risks minimization, reduction of operating costs - all these are the results of the introduction of Smart Fields technology systems in the Salym group of oilfields.

Abstract This paper describes a game-changing solution regarding the use of metal expandable annular sealing systems in a high pressure multistage frac well. The design and engineering of this technology resulted in the development of fit-for-purpose equipment that overcame challenges often encountered in a high-pressure stimulation environment. The metal expandable annular sealing system was custom designed in order to provide high expansion that can be set in potentially washed out wellbores. The design included a long multi-element sealing system with built-in redundancy to account for fracturing fluid chemical reaction with the rock behind the seals. The system is just under 4 meters, complemented with multi-elastomer seals, each delivering full Delta P capability within a washed-out hole up to 6.5". The unique design allows full rotational capabilities during deployment, minimizing operational risks. The system was run in combination with multi open-close fracturing sleeves and a pressure activated toe sub rated to 10,000 psi for acid fracturing in three zones of a vertical carbonate well – the well was known for its heterogeneity and high reservoir pressure contrast. The use of mechanical packers with short sealing elements would have been challenging and increases the risk of unwanted communication between zones. Successful installations, activation of the sleeves and subsequent hydraulic fracturing were achieved, which enabled operational flexibility, reliable isolation and high expansion benefits. Acid fracturing treatment data from each of the stages were analyzed and used to confirm that the zonal isolation integrity. This paper includes the challenges of providing zonal isolation with conventional packer designs and details the design, testing and qualification of the solution as well as further design modifications for higher fracturing pressure rating.

Abstract The selection of proppants is quite a challenging task as the cost almost comprises 20% to well over 50% of total fracturing jobs when ceramic is used. So, in the current situation of oil price crises, optimizing the proppant cost in Pakistan, where fracturing cost is twice as compared to the United States of America, not only provide better-optimized stimulation but also maximizes the Net Present Value. The objective of this study constitutes of two: firstly, to investigate the various types of proppants for peerless fracture parameters based on the post-frac results by using the FracCade simulator. Secondly, to evaluate the Net Present Value and select the most effective proppant based on the Net Present Value. In this case study, the research is conducted on scrutinization of proppant discretion based on net present value, the reservoir data under the study is real-time data of x-well of Tobra formation. The average permeability of the formation is 1md. The focus of this project is to investigate the effects and potential of 25 proppants on hydraulic fracturing treatment. Prior to the selection of the proppants for the evaluation of NPV, sensitivity analysis is done based on closure stress and fracture parameters to screen out 20 proppants. The final selection of proppant is made on the Net Present Value (NPV) which will decide which proppant will give the economic edge to the fracturing treatment. The result of the study is based on the investigation of 25 proppants based on the Net Present Value (NPV) of the fracturing treatment. Before the selection of the proppants for the evaluation of NPV. Almost 20 proppants have been screened out based on the closure stress and fracture parameters. Finally, 5 proppants after technical scrutinization are selected for the evaluation of NPV. From 17 proppants, 5 proppants are selected based on fracture conductivity. These are selected for the evaluation of NPV. Among the 25 proppants, proppant which gives the highest Net Present Value (NPV) is Sintered Bauxite which enhances the well productivity up to 3.5 times and gives the Net Present Value (NPV) of $12,548,762.98.

Abstract To effectively simulate the performance of unconventional wells, it is essential to incorporate sufficient geological complexity to allow for realistic variability in the petrophysical and mechanical properties controlling the productivity of the effective stimulated rock volume. The heterogeneous and strongly layered nature of unconventional reservoirs requires appropriate representation of the high intra-bed contrast in anisotropic deformation and flow behavior, and the representation of pre-existing mechanical discontinuities (faults, bedding planes and natural fractures) in terms of mechanical and hydraulic coupling. These fundamental requirements cannot be achieved unless a high-vertical resolution petrophysical and geomechanical model is developed. As demonstrated in this paper, without integration of high (cm-scale) vertical resolution data such as borehole images and core X-ray computed tomography (CT) images, standard meter-scale petrophysical and geomechanical outputs typically used for Hydraulic Fracture (HF) and flow modeling are, at best, standard scalar log (~m-scale) average compositional volume-weighted representations of subsurface reality, that can be highly misleading when considering that mechanical and flow properties are actually ultimately controlled by fine-scale contrasts and extremes, rather than by arithmetic composition weighted averages. This paper presents an integrated workflow to model mechanical properties at sufficiently high resolution (cm-scale) to accurately honor rock fabric and its effects on HF (height and complexity) and therefore on production. The workflow relies on (1) a novel experimental geomechanics technique and associated analytical solutions to derive poroelastic anisotropy (Young's modulus, Poisson's ratio and Biot's coefficient in the bed-normal and bed-parallel directions) and (2) a joint, high vertical resolution, multi-physics petrophysical model relying itself on (2.1) a standard vertical (m-scale) resolution multi-physics log-based petrophysical output (average composition) automatically redistributed into a high vertical resolution well framework by using (2.2) local constraints from high-resolution data (borehole resistivity image and core dual energy X-ray CT images) coupled with neuronal-network derived core empirical relationships. Core-scale poroelastic predictors defined in (1) are then propagated into (2) to get high vertical resolution geomechanical properties and sub-surface stresses. Beyond providing appropriate inputs to HF modeling, this high vertical resolution well framework enables (i) detailed well-scale calibration and recognition of facies and stacking patterns; (ii) accurate and core-calibrated geochemical, petrophysical and geomechanical characterization of individual beds, and (iii) identification and characterization of discontinuities, in general, and interfaces between beds, in particular. Once upscaled, outputs of this workflow enable a more realistic borehole-view of reservoir quality, fluid flow units and geomechanical stratigraphy – all key information to a more optimal asset development.

Abstract Technology gaps to harness source rock or shale, unconventional reservoirs in the Middle East and North Africa pose unique challenges. Carbonate reservoirs, supplying Ca 2+ ions resulting in passivation of traditional magnesium-based water reactive alloy alloys and abundance of H 2 S/CO 2 rich production fluids at high pressure high temperature downhole conditions cause unpredictable degradation of plugs. This leads to the technology gap, an economical prediction mechanism to assess the degree of dissolution for deployed tools, which has prevented rapid uptake of water reactive alloys in these markets. Here we present, materials and methods to design and manufacture water reactive (fully dissolvable) alloy plugs for multi-stage stimulation (MSS) AKA hydraulic fracturing for the Middle East and North Africa (MENA). The backbone of our water reactive plug is a self-articulating amorphous and bulk nanocrystalline alloy and/or partially or fully vitrified dissolvable material with artificial intelligence (AI), sensing in its DNA, with an ability to learn from the environment it is deployed in. Additionally, these materials will deploy articles that relay information from downhole to surface without conventional telemetry. Other embodiments of the technology building blocks encompass novel, multi-layered smart water reactive nano-materials, further enhancing tailored and timed dissolution.

Abstract Halfaya oilfield in Iraq, discovered in 1976, contains multiple vertically stacked reservoirs. Currently main oil reservoirs are under primary development. The remaining deepest high GOR, HP/HT carbonate reservoir with original pressure gradient of 0.867 psi/ft has been drilled, tested, but undeveloped. An innovative production strategy has been put forward highlighting that high GOR crude can be injected into the upper oil reservoirs with partially pressure depletion, as energy-conservation measure, in view of its high wellhead pressure and good productivity during drill stem tests, therefore to achieve production enhancement and synergy among reservoirs. In-house studies indicate high GOR crude can be miscible with all oils from eight zones. Field results show that injection processes can bring dead wells back production, yielding the prolific output. Also, water cut can be reduced immediately and field water cut rising trend can be mitigated. The innovative injection processes are illustrated as follows: New development wells should be deployed at updip positions to penetrate the all the hydrocarbon reservoirs with the thick pay. Run tubing string with packer. Packer is used for isolation of upper oil zones and HP/HT environment. Huff and puff process. After perforation, high GOR crude travels up the tubing string, via surface choke and a manifold with flow meter, then enter the annulus. Choke regulates the injection rate. For low-permeability (<0.1md) carbonate reservoir, e.g., Sadi reservoir, huff and puff processes are applied post multistage fracturing treatment. High GOR flood is preferred in majorly producing reservoirs with high productivity and relatively low GOR, e.g. Mishrif reservoir. Injected high GOR crude (API=32.7) can dilute remaining oil (API=19.1-23.0), reduce its viscosity, and therefore achieve production enhancement. During primary development, asphaltene deposit occurred and chemical inhibitor has been applied. After oil blending, the risk of asphaltene deposit could be minimized. First perforate lower-pressure oil zones and then open the HP/HT zone for work safety. The production enhancement strategy and processes in this paper could be of strong reference value to similar stacked reservoirs.

Abstract Highly efficient multi-stage hydraulic fractured horizontal wellbores are the dominant completion method for many basins worldwide. This completion workflow is followed with the well start up operations, usually consisting of the frac-plug drill out (FPDO) and the well flowback, designed for preparing the well to the production period. Poor management of FDPO and flowback operations on wells with freshly constructed hydraulic fractures, may jeopardize the investments made in completing the well, and may seriously reduce the well’s profitability. Previously reported results show that flowback and initial production practices have a major impact on proppant production, maintenance and disposal costs, and the subsequent well performance. In this paper we present the summary of the results obtained from the analysis of over 200 FPDO and flowback operations in the United States and Argentina. These results show that operating a well within the safe stability limits of the hydraulic fracture network minimizes risk of fracture damage and maximizes well performance. Earlier it was shown that typical plug drillout operations consists of a series of underbalance, overbalance and balance periods. Multiple rapid transitions between these conditions and performing plug drillout operations outside of the fracture stability limit, was shown to destabilize the proppant pack and mobilize proppant from the fractures. In this paper we evaluate the impact of the various plug drillout strategies on the proppant distribution in the fracture, and draw conclusions about the strategies that help to preserve fracture conductivity. We also demonstrate that using high-frequency monitoring of the surface rates is key for managing plug drillout operations to minimize mobilization of the proppant from hydraulic fractures. Use of the recently introduced Secure Operating Envelope (SOE) concept was found to be very beneficial for managing well flowback and the production operations. In this paper we demonstrate how the use of the SOE methodology was used for identification of the root cause of the proppant flowback and deriving the appropriate choke management strategy for solving this problem. At the end we conclude that majority of the highlighted problems can be solved through optimizing the well start up operations as a part of the entire well construction process with making changes to the well construction workflow. Implementing certain changes to fracture treatment design should enable maximization of the well production performance and optimize the well economics.

Abstract To understand the behavior of hydraulic fracture in the rocks with heterogeneous particles, layer interface and natural fractures, this study carried out a series of experiments of hydraulic fracturing, utilizing a transparent device and an optical microscope for observing. The whole process of rock deformation during the fracturing had been record automatically and the digital image correlation method was used to analyze the deformation and strain of rocks. Several hydraulic fracturing experiments were conducted on difference stress state and rock features. The results showed that large particles had much influence on the fracturing path which could over the stress restriction and make the fracture divert, bifurcate or stop. The interface between two layers with different particle size may make fractures deflect like light refraction. The strain analysis showed that before the final fractures generated represented by a pressure drop, much deformation along the final fracture path had already occurred. That meant that the fracture path had been determined before the pressure drop, and the fracturing fluid influence the fracture path mainly by the penetration. This study can help know the law of hydraulic fracturing in real rocks and optimize numerical fracturing models.

Abstract Successful completion and performance of a horizontal well is one of the most dynamic and complex tasks within the oilfield industry, especially when conventional well is an underperformer. Sustaining production from tight reservoirs with conventional stimulation techniques is one of the most challenging tasks. The reservoir of interest is a tight, low permeable carbonate with thin layers. Productivity proven insignificant with considerable in place volume. The objective is to increase and sustain productivity of a pilot well that consists of an open-hole completion. Multi-disciplinary data is reviewed in a systematic way to identify reasons of low productivity and to identify possible solutions. After comprehensive studies and risk assessments, it is concluded to re-complete well with cemented Frac string to perform hydraulic fracturing with Plug and Perf (PnP) technique. This technique is applied within a conventional tight reservoir, allowing for the flexibility of stage count, stage spacing, and multi-cluster design in order to maximize the stimulated reservoir volume (SRV) along 2,000 ft. in upper layer, 1,000 ft. across middle layers and 2,000 ft. in lower layer. In addition, company and service provider collaborated to enhance this design through a zero over-flush technique along with diverting agents. Core, logging data collected from pilot hole is used to build 1D Mechanical Earth Model (MEM), which is further calibrated with MiniFrac performed with Wireline Formation Tester (WFT). A challenge is to avoid Frac height growth towards underlying reservoir, which is separated by dense carbonate layer of 40 ft. Extensive modeling is conducted in order to choose correct Frac design along the lateral in which landing depth is variable in different target layers of interest that added complexities to Frac Fluid selection. Finally, two Frac systems are selected for different segments of the lateral. After running a cemented casing, Six (06) Acid fracturing treatment and five (05) Proppant fracturing treatments are successfully executed in the lower and upper layers respectively. A comprehensive production test is performed to evaluate and compare the testing results of pre and post frac well. To evaluate the contribution of each stage, a Production Logging Tool (PLT) is deployed. The PLT tool shows the contribution and flow distribution across all the clusters and the efficiency of the Frac design and diversion technique/system. This paper summarizes the design processes, selection criteria, challenges, and lessons learned during design and execution phases. It may provide a potential approach for selecting the proper hydraulic fracturing (Acid Vs Prop) and technique (PnP with clusters Vs PnP with one set of perforation). Company has significant portfolio of undeveloped tight carbonate reservoirs with low productivity and considerable volume in place. This technique will pave the way for developing these reservoirs.

Abstract The instant global trend towards developing tight reservoir is great; however, development can be very challenging due to stress and geomechanical properties effect in horizontal well placement and hydraulic fracturing design. Many parameters are known to be important to determine the suitable layer for locating horizontal well such as petrophysical and geomechanical properties. In the present study, permeability sensitivity to stress is also considered in the best layer selection for well placement. The permeability sensitivity to the stress of the layers was investigated using measurements of 27 core sample at different confining stress values. 1-D mechanical earth model (MEM) was built and converted to a 3-D full-field geomechanical model to reach perfect layer choice. The analysis of results has diagnosed the maximum horizontal stress direction of NE-SW as determined using both Fullbore Formation Micro Imager FMI and sonic scanner anisotropy analysis. The effect of porosity and permeability compaction as a result of stress changes while reservoir depletion is including on the reservoir simulation model. The choice of best layer and optimum design criteria for hydraulic fracturing is done in the current study using a compaction simulation model with the results of available measurements of geomechanical properties. The results of the simulation model show that the formation sensitivity to stress is an important factor for detecting a suitable layer for horizontal wells placement. The results of MEM indicate that horizontal stress difference (Δσ) and unconfined compressive strength (UCS) are the most important factors among geomechanical parameters affected the layer selection. From simulation results, it was found that 225 to 275 m fracture half-length gives a higher increment in oil production. The optimum number of fracture stages is noticed to be 8 to 10 stages after which the increment in production will reduce.

Abstract Fishbone Stimulation Technology was developed to increase the well productivity from the tight reservoir for maximum hydrocarbon recovery. Additionally, this technology was implemented in a thin reservoir where conventional stimulation techniques have not been effective and very risky for more aggressive stimulation technique such as hydraulic fracturing. The application of Fishbone Stimulation Technology was the first time experience representing a massive uncertainity. Thus, a multidisplinary team was estasblished, including members of different departments of the operator and contractors, to design the operational procedures, conduct risk assessment, contingency plans, technical requirements and technical limitations. this first implementation of the fishbone stimulation in ADNOC Onshore served as the benchmark and reference for other fishbone candidate wells in ADNOC Onshore and other ADNOC subsidiaries. The deployment of the equipment and the production results were a complete success overcoming the risks and previously mentioned uncertainities, closing some gaps from previous partial effective applications in other companies. The Fishbone stimulation technology will help to increase the well productivity via below mechanism in a well that is too risky to be hydraulically fractured and beyond the coiled tubing reach: Extension of the needles to connect natural fractures and vertical layers (for reservoir with poor Kv/Kh) Increase reservoir contact Sweep Efficiency of the reservoir