Abstract The Ostracod formation in the Awali brownfield is an extremely challenging layer to develop because the tight carbonate rock is interbedded with shaly streaks and the presence of a nearby water-bearing zone. Although the Ostracod formation has been in development since 1960, oil recovery has not yet reached 5% because past stimulation attempts experienced rapid production decline. The current project incorporated aggressive fracture design coupled with a unique height growth control (HGC) workflow, improving the development of Ostracod reserves. The HGC technology is a combination of an engineering workflow supported by geomechanical modeling and an advanced simulator of in-situ kinetics and materials transport to model the placement of a customized, impermeable mixture of particles that will restrict fracture growth. The optimized treatment design included injections of the HGC mixture prior to the main fracturing treatment. This injection was done with a nonviscous fluid to improve settling to create an artificial barrier. High-resolution temperature logging was used before the main treatment to calibrate and optimize the pumping schedule, and fracture geometry was measured independently with an acoustic scanning tool after the stimulation. The high clay content within the Ostracod layers creates a significant challenge for successful stimulation. The high clay content prevents successful acid fracturing and leads to severe embedment with conventional proppant fracturing designs. We introduced a new approach to stimulate this formation with an aggressive tip-screenout design incorporating a large volume of 12/20-mesh proppant to obtain greater fracture width and conductivity, resulting in a significant and sustained oil production gain. The carefully designed HGC technique was efficient in avoiding fracture breakthrough into the nearby water zone, enabling treatments of up to 450,000 lbm to be successfully contained above a 20-ft-thick shaly barrier with small horizontal stress contrast. Independent measurements proved that the fracture height was successfully contained. Wells treated with this optimized workflow produced up to 22,000 bbl of oil within first 8 months with negligible water cut, which significantly exceeded all previous stimulation results in the field. This trial campaign in vertical wells proved that the combination of aggressive, large fracture designs with the HGC method could help unlock the Ostracod's potential. The applied height growth control technique was modified with additional injections and improved by advanced modeling that only recently became available. These contributed to a significant increase of treatment volume, making the jobs placed in the Ostracod some of the world's largest utilizing HGC techniques. The experience gained in this project can be of a paramount value to any project dealing with hydraulic fracturing near water formation with insufficient or uncertain stress barriers.

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 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 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 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 shale revolution has extended the life cycle of the oil and gas industry, promoted the growth of global oil and gas reserves and production, and changed the energy's strategic pattern of various countries. At present, the national shale-gas demonstration area of PetroChina Changning and Weiyuan is in the stage of large-scale production. Horizontal well and hydraulic fracturing are two key technology that have proven to provide an effective way to economically develop medium to high maturity shale gas resources. However, due to geological complexity of the shale-gas demonstration area, and the lack of robust analysis and research on overpressure mechanism and wellbore instability characteristics, drilling events such as stuck pipes, lost circulations and inflows occurred frequently during horizontal well drilling. These non-productive events greatly restricts the wellbore construction cycle time and the production of shale gas reservoir. A comprehensive geomechanical study was carried out from which the three pressure profiles required for drilling, i.e., pore pressure, collapse pressure and fracture gradient, are established. The study also clarified the spatial distribution of overpressure across the field. The improved pore pressure and geomechanical understanding of the field provides the necessary inputs for an integrated, multi-disciplinary approach carried out during pre-drilled analyses, real-time monitoring and post-drilled evaluation to manage the stability of horizontal wells. The safe mud weight window derived from geomechanics provides the basis for mud weight and mud formulation designs that can be continuously optimized to improve wellbore stability and reduce drilling risks. The integrated approach has been applied for 4 horizontal wells in Weiyuan's shale gas field. One of the wells, Wei202-H34-3, has the horizontal section length of 2500m, making it the longest horizontal section recorded in the block. Drilling performance analyses of the well showed that the overall drilling risk, the wellbore construction time, and the drilling costs were substantially reduced by optimizing the drilling operations through geomechanics integrations and applications. The experience and knowledge obtained from this integrated workflow will provide guidance and serve as reference for the efficient development of unconventional oil and gas reservoirs in China.

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 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 Sand production in oil/gas wells is an important topic wherein a proper engineering planning is required either to avoid, control or manage it. Ignoring this phenomenon may lead to an unfavorable impact on the overall economics of the field development with additional costs incurred to fix the issues at a later stage. Sand production is normally manifested due to sandstone rock failure. The failure sometimes only manifests at later stages of hydrocarbon production associated to depletion (stress evolution). Therefore, finding the root cause of the failure mechanism and routes to avoid it, is essential. In order to achieve this objective, a proper sand production prediction analysis is required using a geomechanical model. Selection of methodology and technology will be key for accuracy of the prediction, analysis and solution. We proposed a few techniques in this article, that can be adopted during the process to design the best engineering solutions to mitigate sand production. Both simple analytical models and advanced FEM numerical models have been discussed in the paper. The selection of methodology should be based on the overall sand production risk level even though FEM techniques is the best for solving the problem.

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 Sand production can cause serious chaos at the wellhead and needs a proper geomechanical analysis to understand the failure and post failure mechanisms. Thus, a proper constitutive model (failure criteria) is required for this effort as most of the available failure criteria are not specially developed for sandstone. The post failure (Softening) part is not normally captured in many of the existing models. For this reason, a new elastoplastic constitutive model for sandstone has been investigated and developed. A serious attempt was made to capture both the hardening and softening of the sandstone rock. The effort started in the laboratory with a series of triaxial tests conducted for different confining pressure for 3 types of sandstone. A systematic approach has been used to analyses the rock mechanical data to pick proper yield, peak and residue strength, besides common elastic properties. A new constitutive model is then developed and validated. The new constitutive model (known as Assef-Surej-Ariffin, ASA model) is able to capture the full elasto-plastic rock mechanical behavior including softening and post failure which is critical for oil and gas applications such as sand production and drilling. An FEM code is used to validate the new constitutive model and the results compared with the modified Mohr Coulomb criteria. The results show that the new ASA constitutive model gives a better match for most of the laboratory tests compared to Mohr Coulomb especially for the softening part. The new ASA failure criteria is planned to be used in sand production analysis to estimate the sanding propensity and rates where the post failure analysis will be key to the results.

Abstract The application of MHFHW (multistage hydraulic fracturing horizontal well) enormously contributes to the dramatic increasing production of low permeability reservoir. Geomechanics is the key factor for fractured well by influencing SRV (stimulated reservoir volume) and post-stimulation production. Stress variation and distribution characteristics along with real-time fracturing are simulated based on 4D (four-dimension) geomechanics research, providing the effective technical support for the designing and optimization of hydraulic fracturing scheme to get larger SRV and higher post-stimulation production. 1D (one-dimension) geomechanics model is firstly built using data from drilling, mud log, well log, mini fracture and well testing, and then verified by comparing with drilling events and laboratory test of core samples. Furthermore, Project team combines 1D geomechanics model with additional data including 3D structural model, fault distribution and seismic data to achieve the regional 3D (three-dimension) geomechanics model. 3D Geomechanics model only represents the original stress field that before hydraulic fracturing, which will be changed by pumping massive fracturing fluids into reservoir. 3D geomechanics model study is integrated with the data from real-time fracturing and micro- seismic monitoring to generate 4D geomechanics model, enabling the characterization of variation of geomechanics model with real-time fracturing. 4D Geomechanical research result clearly characterizes the stress model variation and reduces the uncertainties in reservoir stimulation operation. The model helps to optimize pressure pumping rate, volume of proppant and fracturing fluids, eventually maximizes the increase of fracture flow conductivity and post-stimulation production., This case study discusses the multi-stages fracturing treatment scheme optimization of horizontal well H84001 based on the 4D Geomechanical research of this low permeability reservoir. H84001 production has improved 184.2% compared with the offset well without fracturing treatment optimization. This project established the mathematical relationships between reservoir deformation and strain, upgrading geomechanical study methods from static to dynamic. The research finding provides technical guidance to develop low permeability reservoir in an economical and efficiency stimulation scheme.

Abstract The recent surge of interest in developing tight resources in the United Arab Emirates (UAE) has been accompanied by a growing appreciation of geomechanics challenges with potentially far-reaching implications on successfully placing and producing from stimulation treatments. The challenges are mostly posed by regional tectonics and localised "stress regime" changes from normal faulting to strike-slip. Therefore, understanding the in situ geomechanical conditions plays an important role in optimising stimulation designs and recommending safe drilling mud weights. In this study, a 3D mechanical earth model (MEM) was built by comprehensively integrating data from multiple sources—including interpreted mechanics and lithology information such as stresses, stress direction, and core results. This 3D geomechanical model covered the target reservoir and extended from the surface to deeper formations to fully capture geological structures with high resolution. A set of faults was also incorporated to help examine their impact on well planning. Sensitivity analyses were conducted to account for uncertainties in mechanical properties and local tectonic stress state. The 3D MEM successfully captured the observed drilling events in the thin weak inter-layers between the target reservoir for multiple wells. Some faults were shown to be critically stressed at present day. Risk of fault reactivation would increase with future production, and horizontal drilling may become increasingly difficult. The horizontal stresses in the target reservoir were significantly affected by porosity. Specifically, the low-porosity zones may have strike-slip stress regime, while high-porosity zones are in a predominantly normal faulting stress regime. The geomechanical modelling approach helped qualitatively highlight the variations in fracture containment (for a range of ‘net pressure’ thresholds), thus demonstrating the risk of breaching in a reservoir seal. It is moreover an interesting side effect that this geomechanical modelling ‘recipe’ provided invaluable insights into delineating potential ‘sweet spots' for stimulation—essentially characterised by having high porosity and low breakdown pressures. The developed 3D MEM helped extend the understanding of subsurface behaviour beyond a few well locations and historic events. Moreover, the model demonstrated its predictive power in relation to identifying the potential location and pressure boundary for a future stimulation plan ultimately impacting the well placement strategies.

Abstract This paper presents a data-driven model built using machine learning technique, namely Support-Vector Regression (SVR), for predicting rock mechanical properties (RMP) of tight sands and shale formations based on measured elemental information. This study utilized 324 data points obtained from Paleozoic sequences covering 8000 ft interval. Elemental data was acquired by scanning intact samples on MicroXRF machine, whilewas used for modelling as well as for establishing lithofacies. RMP were obtained at atmospheric conditions using a non-destructive impulse hammer technique. SVR was used to establish a correlation between elemental geochemical information with RMP. The dataset was categorized into two: training and testing dataset using a 70-30 percent split. Training data was used to train SVR and establish the RMP prediction model by tuning the hyperparameters. Testing data was used to evaluate the predictive model by comparing the predictions with the actual measurement. Two quantitative measures for estimation accuracy including mean absolute error and cross-correlation plots between the actual and estimated RMP were employed to evaluate the prediction accuracy. The results demonstrate that the estimated RMP has a good agreement with the actual RMP, which is indicated by the small error and high coefficient of determination. Moreover, we used Adjacent Boosting technique to perform feature selections and the results show that the SVR-based model still generates good prediction when the number of features in the input is reduced by more than half. This study demonstrates that a reliable predictive model can be built with few intrisinc features, in the absence of robust mineralogical and elemental information.

Abstract Hydraulic fracture design driven by multi-disciplinary collaboration can maximize the production potential of complex multi-frac horizontal wells. Integration of multiple information sources (i.e.: geological, dynamic and geomechanical data) allows to build representative models and have proven to improve modelling towards a realistic understanding of tight reservoir performance of several multi-fracced wells. 3D properties encompassing the reservoir geological heterogeneity, pore pressure, mechanical elasticity and state of stress were utilized to develop a strategy to fracture stimulate a horizontal wellbore in the North Sea Region. The study was instrumental to build fit-for-purpose hydraulic fracture designs by incorporating state of stress changes related to pore pressure depletion on different faulted compartments supported by a reservoir dynamic simulation. Such models provided meaningful value to optimize the well trajectory used to access the host rock, understand fracture height growth possibilities in different compartments and define the number/size of hydraulic fractures required for optimum production.

Abstract Owing to the low productivity of single well, rapid productivity decline and low ultimate recovery of low-permeability reservoirs, multistage fracturing is usually employed for reservoir stimulation of horizontal wells, which helps to increase fracture conductivity and single well productivity by creating artificial fractures. It is very vital to accurately characterize and simulate 3D spatial distribution of fracture networks for hydraulic fracturing technology. Sufficient production data has proved that the hydraulic fracture geometry simulation integrating 1D geomechanics, without considering natural fractures, resulted in low accuracy of fracture modeling, which could not effectively support the deployment and implementation of oilfield development plan. Thus, artificial fracture networks simulation technology fully coupling 3D geomechanics with natural fracture model will be urgently required to guide oilfield development economically. The technical research process is divided into 4 steps. Step 1, set up 1D geo-mechanical modeling in single well using conventional and image logging data, formation integrity testing, drilling logs, as well as rock mechanical laboratory tests. Then, 3D static geomechanical modeling of the reservoir can be performed by incorporating seismic data and structural modeling. Step 2, identify natural fractures in single well based on image logging data and core data to create fracture intensity curve modeling. Establish 3D natural fracture model constrained by fracture sensitive seismic attributes analysis and 3D fracture intensity trend body. Step3, based on rock and fracture mechanics, simulate hydraulic fracture extension of stimulated well coupling 3D geo-mechanical model with 3D natural fracture model. Then, verify modeling accuracy through micro-seismic data. Step 4, compare and analyze differences in fracture geometry, proppant placement, and fracture conductivity between 3D coupled fracture modeling (3DCFM) and 3D uncoupled fracture modeling (3DUFM). After gridding 3DCFM and 3DUFM to geological modeling, predict production post fracturing using numerical simulation technology. Finally, crosscheck the accuracy of 3DCFM and 3DUFM with predicted and actual production data. By comparing and analyzing the fracture geometry and numerical simulation results of 3DCFM and 3DUFM, it was concluded that 3DUFM could not characterize natural fracture shielding effect and diversion during fracture extension due to 3D geo-mechanical spatial anisotropy. Thus, greater uncertainties of the fracture modeling occurred, resulting in low consistency between single well productivity prediction and numerical simulation. Compared with 3DUFM, the uncertainty of the fracture modeling geometry can be greatly reduced in 3DCFM verified by micro-seismic patterns, so the consistency between productivity prediction and numerical simulation will be significantly increased. Hydraulic fracture simulation technology fully-coupling geomechanics with natural fracture model was applied in the low permeability fractured reservoirs of the northwestern margin of Junggar Basin, China. The cross-over analysis among research results, the actual micro-seismic patterns and production data indicated that compared with 3DUFM, the uncertainty of 3DCFM reduced by 25.2%;, and the consistency of numerical simulation and productivity prediction increased by 18.5%. The research results would be a guideline on location optimization of horizontal wells, stimulation optimization of multistage fracturing and strategy optimization of oilfield development.

Drilling wells in some locations in the Greater Burgan field in Kuwait, can demonstrate significant challenges across the intermediate section. Part of these challenges are combining the carbonate formations with the weak unstable Ahmadi shaley formations at the bottom of the section. This makes it challenging to drilling engineers and difficult to balance between natural mud losses across the carbonate formations and weak shale that requires higher mud weight. Adding to these challenges, the limited surface locations in the field, that forces the well design trajectory to be deviated, which makes the mud window even smaller and shifts it higher. Zonal isolation across this interval adds an additional challenge, as it will prevent gas and liquid to escape from high pressure deeper zones to shallow lower pressure zones and probably to surface, which potentially may cause well integrity issues in the future. This paper represents a case of formation collapse on a casing prior to cementing operation, how it was detected, how it was handled and how successfully the well was completed.

Production of shallow gas has presented a unique opportunity to implement a fit for purpose fracturing workflow due to the level of complexity these reservoirs present. Initially acquired logging data including open hole logs, mud logs, wireline pressure measurements and reservoir sampling as well as micro-frac readings confirmed the presence of relatively shallow gas in low permeability rock. Hence introducing fracturing as a favourable method of extraction made it imperative to address the level of complexity within the reservoir, which varied from the presence of anhydrites, extreme heterogeneity, water sensitivity, as well as the fault environment at such shallow depths. Exploring pilot holes and running advanced image logs as well as acoustic measurements along with micro-frac operation, provided critical data for completion design improvement to not only enhance the chances of successful placement, but also increase the overall gas output. The relatively low bottom hole static temperature and pressure, soft rock, heterogeneity and overall immaturity of the reservoir required extensive core flow tests. X-Ray Diffraction (XRD) as well as lithology scanner logs were also used to fully understand the complex mineralogy. A suitable salt tolerant fluid was proposed for fracturing before optimisation as well as the inclusion of fit for purpose acid systems. The workflow also utilised the extensive geomechanical datasets for analyses, as well as incorporating the geological and petrophysical interpretations. This was followed by sensitivity analyses of the fracturing design based on size of stages, stage spacing, cluster spacing, as well as the cement quality. After performing micro-fracturing tests, a one dimensional mechanical earth model (1D MEM) was optimised to enable better understanding the fracture geometry. The workflow also included the use of chemical tracers to qualify the success of each fracturing stage within the target horizontal section. The workflow started with a collaboration between geology, geomechanics, petrophysics, reservoir, as well as stimulation domains, which resulted in the completion of the first horizontal multistage fracturing completion within the targeted shallow gas reservoir. This milestone provided insight into the required planning for future gas wells within the region and has left significant potential for optimisation given the complexity of the reservoir. The consolidation of a workflow to deliver the first shallow gas project in order to extract the initially confirmed gas presence has presented a novel approach to such a niche project. This was initiated by utilising a time-lapse image analysis, petrophysical and reservoir evaluation, and then coupled with the introducing propped fracturing and matrix acidizing to further calibrate log-deduced parameters. A high level of detail in core analysis, as well as micro-fracturing interpretations, have reduced the uncertainty regarding fracture generation, initiation, and fracture extension into the far field in such a shallow and unconsolidated, low temperature and pressure reservoir.

The shale revolution has extended the life cycle of the oil and gas industry, promoted the growth of global oil and gas reserves and production, and changed the energy's strategic pattern of various countries. At present, the national shale-gas demonstration area of PetroChina Changning and Weiyuan is in the stage of large-scale production. Horizontal well and hydraulic fracturing are two key technology that have proven to provide an effective way to economically develop medium to high maturity shale gas resources. However, due to geological complexity of the shale-gas demonstration area, and the lack of robust analysis and research on overpressure mechanism and wellbore instability characteristics, drilling events such as stuck pipes, lost circulations and inflows occurred frequently during horizontal well drilling. These non-productive events greatly restricts the wellbore construction cycle time and the production of shale gas reservoir. A comprehensive geomechanical study was carried out from which the three pressure profiles required for drilling, i.e., pore pressure, collapse pressure and fracture gradient, are established. The study also clarified the spatial distribution of overpressure across the field. The improved pore pressure and geomechanical understanding of the field provides the necessary inputs for an integrated, multi-disciplinary approach carried out during pre-drilled analyses, real-time monitoring and post-drilled evaluation to manage the stability of horizontal wells. The safe mud weight window derived from geomechanics provides the basis for mud weight and mud formulation designs that can be continuously optimized to improve wellbore stability and reduce drilling risks. The integrated approach has been applied for 4 horizontal wells in Weiyuan's shale gas field. One of the wells, Wei202-H34-3, has the horizontal section length of 2500m, making it the longest horizontal section recorded in the block. Drilling performance analyses of the well showed that the overall drilling risk, the wellbore construction time, and the drilling costs were substantially reduced by optimizing the drilling operations through geomechanics integrations and applications. The experience and knowledge obtained from this integrated workflow will provide guidance and serve as reference for the efficient development of unconventional oil and gas reservoirs in China.