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.

The scope of this paper is to discuss and compare the different milling strategies of the frac plugs associated to hydraulic fracturing operations in both, vertical and horizontal gas wells, with formations depleted in Petroleum Development Oman (PDO); the main objective is to describe milling operations and the well delivery improvement by the optimization of clean out and milling strategy. The paper will show the enhancement of the milling operations and the outstanding results. The paper will start by describing the execution of hydraulic fracturing operations in both vertical and horizontal wells, which is mainly related to plug and perf. It will also cover clean out and milling practices for frac plugs in depleted formations. Further, it will discuss the planning and design of the post frac clean outs and milling jobs based on the learnings previously captured. Frac plugs milling operations have been successfully improved in severe depleted vertical gas wells and some horizontal wells with no severe depletion; initially the milling operation was done after all frac stages were completed in depleted wells, out of the critical path, however the experience showed that it was a lengthy and expensive process due to the severe formation losses while milling leading into a very low efficient operation impacting the frac well delivery. The subsequent step was to address the milling after every stage, during the critical path, which increases the cost of daily frac charges. With the use of an innovate downhole technology the milling strategy was changed and optimized showing outstanding results, milling frac plugs was achieved successfully at the end of the job in horizontal wells while in some previous wells the milling was done in between the stages; also for vertical depleted gas wells, fracturing stages have been combined to mill frac plugs together. The completion of the entire wells (well delivery) was achieved in a relative shorter period of time compared to previous wells; this is reflected on actual cost reduction of more than 20% of total cost/AFE The optimization of the frac plug milling operations is a novel approach to enhance hydraulic fracturing and well delivery in depleted gas wells in PDO, this is in alignment with the continuous improvement (CI) ideas and the lean thinking across the oil and gas industry nowadays. It is easy to replicate in other gas fields expected to be depleted, which will reduce cost, Health, Safety & Environment (HSE) exposure and will help increase the recovery of hydrocarbon reserves.

A maturing UAE field has multiple stacked oil and gas reservoirs experiencing differential depletion causing unequal increases in vertical and horizontal effective stresses on reservoirs and bounding rock units. The stress variation has resulted from long-term production with some intervals experiencing a reduction of reservoir pressure of more than 2,000 psi. Moreover, reservoir compaction and pore collapse become more serious with the increasing stress acting on the rock framework—particularly upon reaching a critical pressure value. Laboratory measurements of rock compressibility under simulated in-situ stress conditions were conducted to quantify production-induced changes and evaluate pore volume and permeability reduction as a function of reservoir pressure. Furthermore, integration of lab measurements and logs (well and seismic) is driving a geomechanical model covering a broad view of the stacked reservoirs to provide appropriate pore collapse mitigation measures. Pore collapse implications were examined by conducting geomechanical laboratory testing on representative samples—honoring rock heterogeneity through well logs and continuous core measurements and including uniaxial-strain compression (far-field compaction), triaxial compression (near-wellbore compaction), hydrostatic compression (compactant cap), and constant stress path (fixed Ko, far-field compaction). Laboratory data were combined to evaluate shear failure vs. compaction failure in q-p space (i.e., shear stress vs. effective mean stress). Reservoir depletion was monitored continuously from preproduction in-situ stress to planned abandonment conditions for 10 reservoir sections with varying porosity. Testing conducted on the reservoir intervals under study was designed to capture all possible depletion scenarios during the potential life of the reservoir. This study thus improves the appreciation of the mechanics of rock compressibility—in connection with its strong dependence on reservoir stress path (e.g., hydrostatic compression or uniaxial strain compression) and depletion rate—for addressing problems such as rapid loss in permeability, generation of fines, surface subsidence, wellbore instability, casing deformation, and loss of caprock containment. This paper starts by outlining core analysis workflows that can adequately assess potential changes to reservoirs during depletion, highlighting a workflow for constructing a 3D geomechanical model. The results showed that rock with porosity >25% has a propensity for accelerated compaction prior to reaching abandonment pressure. These results were then integrated with reservoir simulation models for long-term field management, which is part of an ongoing modeling effort. The integration of laboratory testing with seismic-driven geomechanical modeling helps predict the impact of production-induced stress changes on field performance. This will, therefore, aid operators in making life-of-reservoir decisions that relate to compaction mitigation and formation stimulation.

Hydraulic fracturing is the industry-proven technology for efficient exploitation of tight reservoirs. This study evaluated the technology by drilling horizontal wells through acid fracturing the low permeability gas reservoirs of a lower cretaceous carbonate formation, located onshore Abu Dhabi. 1D Geomechanical modeling was critical in determining fracturing strategy. Containment of fracture height growth was the most critical aspect of the fracturing process, as the target units were stacked within heavily depleted reservoirs. The challenge was that the rock strength, poroelastic behavior and stress paths vary significantly through the various formations overlying/underlying to target reservoirs. In addition, the depositional nature of the target reservoirs meant inherent variations in rock mechanical properties. Hence, a continuous profile of in-situ stresses and other rock mechanical properties was essentially mandatory for addressing the challenges for optimal placement of the horizontal drain hole and assessing fracture height growth. Existing rock mechanical measurements, dipole sonic and image logs, as well as in-situ stress measurements were reviewed for 400ft (TVD) interval above and below the target reservoirs. Significant data gathering was managed in the vertical pilot hole of the first well to fill data gaps. A custom-built workflow was performed for 1D Geomechanical modeling in the first well, integrating poroelastic modelling with failure models. The study integrated drilling-induced and production-induced Geomechanical aspects into the 1D stress profile, including depletion-induced poroelasticity, shear anisotropy, and rock mechanical heterogeneity. Wellbore failures observed in vertical pilot hole and the in-situ stress measurements from offset wells were used for validating 1D Geomechanical model. This work resulted in a rigorous 1D-stress profile that contributed to initial fracture modelling, whilst de-risking the fracture height growth into the depleted reservoirs and optimizing the choice of drain hole location within sub-units of the target reservoirs. The fracture gradient and breakdown pressures derived from 1D stress profile were found to be in very close agreement with that measured from the minifrac conducted in vertical pilot hole of the first well. This paper presents a purpose-driven workflow designed specifically for these circumstances. The merit of the workflow lies in its systematic and methodical approach, providing solutions to various Geomechanical problems relevant to the target reservoirs, as well as the depleted reservoirs above and below. The results are beneficial for analogous fields where hydraulic fracturing is required to improve recovery of low permeability reservoirs in mature fields

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.

One of the PDO’s largest producing field with vertically stacked carbonate reservoirs gas from shallower Natih Formation, and produces oil from lower Shuaiba formation with waterflood recovery. Natih formation is a highly compacting formation characterized using rock mechanics laboratory measurements. Currently there are more than 500 Shuiaba wells that are active, which penetrate through the highly compacting Natih Layer above. Reservoir compaction of Natih A has induced damage to several wells most likely due to compression and buckling of the casing within the production interval. The field has obeservations to well integrity and impact to production performation related to the casing deformation resulting from the compaction. The well Integrity issues for Shuaiba wells are being resolved with work over operations, repairs. In few severe cases, it was required to abandon the well. All of these issues impact operational expenditure and production (loss and/or deferment). Risk assessment for wells with future depletion (or time) can provide input to manage the risk, plan adequate mitigations and capture the impact in the future drilling campaigns for well stock. To do so it was important to identify and quantify well counts, which have high potential to have well integrity issues or risk of failure In the studied field, subsurface compaction is being monitored/measured since 2000, using Compaction Monitoring Instrument (CMI) that measures compaction between preplaced radioactive markers in the formation and the casing in five CMI monitoring wells. Data of CMI compaction log, historical well failures, spatial well locations, rock mechanics measurements was integrated to quantify risk of expected well failures in future. The results from the CMI logging showed that the compation in the entire reservoir interval is not uniform and upper layers in the reservoir intervals were subjected to very high compaction strains compared to lower layers. The Uniaxial Pore Volume Compressibility (UPVC)) coupled with analysis of CMI data provides a forecast for maximum compaction strain in the upper reservoir layers up to 5 % at abandonment pressure. The analysis of reported/observed well failures reveals that approximately 77% of the impacted wells were during 1971-2000. Using these inputs a risk assessment matrix for well failures was developed, which provided potential wells with high risk of failure/well integrity issues, which accounted to about 34% (~ 85 wells) of the active wells. Results of this study provided input to capture in the development plans and build adequate mitigations to help minimize production loss/deferment

The use of Recovery-factor (RF) versus Pore Volumes Injected (PVI) plot to assess historical and ongoing water flooding strategy and its conformance is a common practice. However, this technique is rarely utilized to guide the future water flooding plan that are often assessed by dynamic modelling. The objective of this paper is to demonstrate an extended application of classical conformance plot not only for the typical use of historical and on-going water flooding performance evaluation but also as a tool to guide the future water flooding strategy. A collaborative effort between different reservoir management team members were required to obtain the input parameters. This new workflow starts by applying the classic conformance plot technique on prediction scenario of production and injection data from numerical model. In this study, the water flooding conformance plot at layer level is presented. The plot was complemented by the theoretical recovery factor as reference of an ideal water flooding scenario. Subsequently, various injection prediction scenarios from dynamic model were added to the conformance plot template for detailed evaluation. The assessment includes evaluation of water injection rate, timing of water flooding development strategy application, location of injectors and various sensitivity analysis on the injection rates. Some distinct shapes of conformance plots were recognized during the study. Views and opinion are gathered based on this study to identify the new use of conformance plot as a tool to assess the efficiency of different water flooding strategies. The lesson learnt from this study and the identified conformance plot shape can be beneficial to guide the direction of water injection plan to improve the overall field development plan.

The Eocene C-Sup VLG3676 reservoir is one of the most important oil reservoirs of Western Venezuela. It has a high lateral sedimentological heterogeneity, some sand production issues due to low sandstone cohesion and high stress gradients, and asphaltene precipitation problems. All these features have created production problems since the beginning of the reservoir production, with a drastic impact on the reservoir potential. This has lead to the construction of a compositional/geomechanical model in order to design a palliative strategy. The proposed modeling methodology includes nine phases: 1) Development of the 3D mechanical earth model (MEM) to simulate reservoir compaction; 2) Quality control of the static model, including the relative permeability values; 3) Development of a fluid model that predicts the onset of asphaltene precipitation; 4) Development of a rock-fluid interaction model; 5) Initialization and calibration of the compositional model; 6) Coupling of the compositional and geomechanics models; 7) History matching; 8) Analytical estimation of the onset of sand production; 9) Implementation of an opportunity index analysis for asphaltene precipitation and sand production. Based on this compositional/geomechanical model it has been possible to map the risk of asphaltene precipitation and sand production in the reservoir, therefore showing that such problems are critical in the Eocene Misoa C-2-Sup and C-3-Sup stratigraphic units, due to the energy depletion caused by the production. This model allowed optimizing the locations of 35 wells to be drilled. The applied methodology enabled engineers to efficiently estimate the bottomhole flowing pressures and the critical drawdown pressures in the reservoir, identify the most prospective areas of the deposit, and design the trajectories of the new wells. It allowed designing the future Asset Development Plan (ADP) to maximize the hydrocarbon recovery and optimize the resources and investments necessary to increase the reservoir productivity. This paper will go through all the nine phases of the workflow, will highlight their most specific features, and will conclude on the value on such an approach.

The Amin field located in South Oman is one of the PDO's major producing oil fields. The reservoir is good quality sandstone formation with average porosity of 28% and average permeability of 800 mD. Prior to 2014, the field was developed using natural depletion drive during which some parts of the field experienced significant pressure depletion. This depletion was due to combination of high production from the crestal area and the presence of a near field-wide intra baffle (L110), that restricts the aquifer response to the upper layers of the reservoir. The baffle about 2m to 4 m thick is a cemented sandstone with minor shale intercalation that has caused the vertical pressure variation across baffle L110. To arrest the field pressure depletion, water-injection was implemented since 2014, for further field development. Produced water is injected into the aquifer below the OWC of the field through 38 vertical injector wells. To achieve desired voidage replacement injection is expected with fracturing conditions using untreated produced water with injection rates > 1500 m3/day. Bottom hole pressures are at or above formation fracture pressure and decline in injectivity with time has been observed due to untreated water. Geomechanical data and modeling results were integrated with WRM activities, trials data and surveillance technologies to optimize the injection strategy for improved waterflood performance. Geomechanical data was acquired to estimate the formation fracture pressure to provide guidance on maximum allowable injection pressure in injectors with perforations closer to OWC to manage the risk of induced fracture growth. A Produced Water Re-Injection (PWRI) fracture modeling and analysis was performed to determine the potential fracture dimensions to provide input to development decisions of injection rate and perforation depth below OWC. Simulations were carried out with estimated range of formation fracture pressure, Petrophysical parameters, injection rate forecasts and expected water quality parameters e.g. TSS (Total Suspended Solids) The simulation results from the field data calibrated PWRI fracture model indicate that injection higher rates > 1500 m3/day, would result in vertical fracture growth from the injection depth. The rate of fracture growth is primarily influenced by water quality and depth of injection. Formation fracture pressure decreases with depletion therefore once the vertical fracture propagates and enters into the upper reservoir zone, fracture growth will be accelerated. Results indicated that if injection depth closer to OWC can result in short-circuiting as early as 2 years for certain field area. Higher injection rates to meet the desired voidage replacement ratio has significant impact on the field's waterflood performance. Results provided inputs to reservoir simulations and injection rate envelope for varying perforation depth below OWC. The study benefits the field to minimize risk of injector producer short-circuiting for improved waterflood management.

Heterogeneous nature of the Cretaceous carbonate reservoirs in Abu Dhabi increases there complexity to attain efficient characterization and hence development. During depletion, reservoir pressure reduction results in unequal increase of vertical and horizontal effective stresses and thus an overall increase in the effective mean and shear stresses on the reservoir pore structure. At reservoir pressures below a critical value (obtained via laboratory testing or post failure field analysis), the reservoir compacts at accelerated rates. Compaction and its associated reduction in reservoir pore volume leads to rapid loss in permeability, generation of fines and wellbore stability issues (e.g., casing collapse). Assessing the magnitude of these changes require laboratory measurements of rock compressibility (grain, bulk and pore compressibilities), and concurrent evaluations of reduction of pore volume, porosity and permeability as a function of reservoir pressure needs to be appropriately simulated in-situ stress conditions. Poor appreciation of the rock compressibility mechanics and its robust dependence on stress path (e.g., hydrostatic- and/or uniaxial strain compression) in addition to depletion rate may result in substantial cost. The core intervals are selected to capture the lateral and vertical heterogeneity encountered in the studied reservoirs. The test program was designed to create a material model to capture the rock response to potential reservoir pressure changes. Single Stage Triaxial tests at multiple confining stresses were conducted to judge the shear failure. Tests recommended for evaluation and assessment of reservoir compaction are Uniaxial-strain compression (far-field compaction), triaxial compression (near wellbore), Hydrostatic (define the compaction cap) and constant stress-path. Additional tests were carried to characterize the poro-elastic response of reservoir rock and the stress-dependent permeability. A combined failure envelope (defining shear (dilatant) and compaction ("Cap") for compactable sediments) of the rock was generated by integrating the results from Single stage Triaxial tests (Shear failure envelope), hydrostatic compression tests and UPVC tests (Compaction failure envelope). For field applications, it is useful to provide a visualization of the pre-production-state in-situ stress conditions, and the possible stress path trajectories of the reservoir, as a function of reservoir depletion. Such a failure envelope was generated for all the different lithofacies encountered across the field. The characterized material model enables us to assess and predict the risk of shear/compaction deformation associated with the reservoir pressure changes (considering field stress path). Using this display, the level of depletion resulting in accelerated compaction can be identified through laboratory testing. The introduced workflow presents a comprehensive geomechanical characterization program for such complex carbonate reservoir. This utilizes a systematic approach to generate field wide understanding of rock response to depletion and injection. It can also act as a guide to address the compaction-based challenges faced in other reservoirs of Abu Dhabi.

Wells that are used to recover hydrocarbons from reservoirs are subjected to large amounts of complex geomechanical loads that may compromise the well's integrity over its operating lifetime. While the reservoir depletes, the pore pressure in the rock reduces and the effective stress in the rock formation increases. As a result, the rock deforms and the reservoir experiences an overall volume reduction (compaction). Under such compaction, any well casing experiences a substantial amount of compressive and shear stress/strain in all directions. In order to ensure safe operation of a well, it is necessary to impose operational limits (drawdown and depletion) so that stresses imparted on the casing do not exceed the casing strength. This problem has been studied in the past [ 1 , 2 , 4 , 6 , 8 , 10 ] and due to computational complexity and cost, past methodologies have used simplified analytical solutions or decoupled modeling by separating the large scale deformation of the rock (3D model) from the casing behavior (2D model). These simplified methodologies rely on choosing an a priori failure mechanism and also make assumptions on how the load transfer happens between the rock and the well hardware. Based on our experience, this approach is conservative and leads to poor approximations. In this study, a fully detailed two-scale 3D Finite Element (FE) model is used to simulate various drawdown and depletion combinations derived from a reservoir model simulation. The large-scale model captures the far-field effects of drawdown and depletion as well as the effects of neighboring producer wells. The small-scale model includes details such as casing, cement, perforations, and surrounding rock. This approach is not constrained to a specific failure mechanism (axial compaction, pipe collapse, bending or shear), but rather includes all possible deformations based on rock mechanical behavior, stress, pressure change, and geometry. Thus, complex casing deformations with different failure locations can be observed. This technology has been applied to a number of business units within ExxonMobil, allowing us to establish practical drawdown/depletion limits. In this paper, we discuss a field example of this approach.

Following decades of production from multiple separated stacked reservoirs, a maturing field has undergone many subsurface activities, such as drilling, oil and gas production, and injection of water and gas for reservoir stimulation. Considering the long-term field development plan, one reservoir will be depleted by 5,000 psi after 20 years. Such high levels of depletion can produce severe reservoir compaction and pore collapse, leading to a rapid loss in permeability, generation of fines (byproducts of pore collapse and/or grain crushing), subsidence, wellbore instability, damage to well completion integrity, and loss of caprock containment. An extensive rock mechanics laboratory study was conducted to assess the possibility of pore collapse and prevent and mitigate risks proactively from adverse reservoir compaction. During depletion, the reduction in reservoir pressure results in unequal increases in vertical and horizontal effective stresses and thus an overall increase in the effective mean and shear stresses on the reservoir. At reservoir pressures below a critical value (obtained via laboratory testing or post-failure field analysis), the reservoir may compact at accelerated rates. To fulfill the objective of this study, a series of tests were designed to probe all possible depletion scenarios. Rock failure parameters were evaluated through a sequence of tests of carefully selected, representative samples. Failure envelopes defining shear (dilatant) and compaction ("cap") for compactable sediments are often strongly nonlinear. For field applications, it is useful to provide a visualization of the preproduction-state in-situ stress conditions and the possible stress path trajectories of the reservoir (from triaxial K o =0 to hydrostatic K o =1) as a function of reservoir depletion. Using this display, the level of depletion resulting from accelerated compaction was identified through laboratory testing. Tests conducted for assessment of reservoir compaction are: uniaxial- strain compression (far-field compaction), triaxial compression (near-wellbore compaction), hydrostatic (define the compactant cap), and constant stress-path (fixed K o , far-field compaction). The rock units evaluated were exceptionally heterogeneous, with tensile strength and unconfined compressive strength ranging from 323 to 2,987 psi and 2,944 to 34,481 psi, respectively. Testing conducted on the reservoir intervals were designed to capture all possible depletion scenarios during the potential life of the reservoir. Results have shown that rock with porosity >26% have a propensity for accelerated compaction prior to plan abandonment pressures. Further, accelerated compaction does not occur for rock with porosities below 25%, even following extreme reservoir depletion of 5,000 psi. This paper outlines core analysis workflows that can adequately assess potential changes to reservoirs during depletion—from preproduction conditions to abandonment. Further, the paper highlights the importance of understanding rock heterogeneity prior to initiating any core analysis program.

The Barik Deep clastic gas reservoir was discovered in 1991 and has been on production since 1994. It is a very rich gas condensate reservoir with initial Condensate to Gas Ratio (CGR) of 1100 m3/MMm3. With reservoir pressure dropping below dew point (428 bar vs. initial pressure of 478 bar), a huge volume of condensate has dropped-out inside the reservoir as confirmed by production data and the deterioration of well performance. As of 1/1/2018, the Barik Deep reservoir is developed with 29 gas producers out of which 7 wells are closed-in mainly due to liquid loading. The reservoir is currently producing above 2 MMm3/d of gas and ~400 m3/d of condensate and reservoir pressure is around 230 bars. An integrated subsurface-surface study was started in 2017 with the objectives ∘ To propose an integrated plan for re-developing the Barik Deep ∘ To identify solutions to maximize recovery of the dropped-out condensate ∘ To resolve condensate banking issues and its impact on productivity ∘ To identify new technologies allowing to increase production, to increase the field recovery (gas and condensate) and to propose a maturation plan for these technologies. In a first phase of the project, a detailed analysis of all data collected over years of field development have been used to achieve a step enhancement in the understanding and characterization of the condensation process in Barik deep. In a second phase, the study involved the construction of compositional model capturing the physics of the condensation phenomena (i.e. very refined single well models) in order to assess various condensate recovery options. This effort supported the later building of full field simulation models to evaluate the impact of the most promising recovery techniques on recovery at field scale. This paper covers: The interdisciplinary novel data analysis workflow approach followed to determine the critical elements of the condensation process (PVT, SCAL, pressure depletion, reservoir properties,...etc) The quantification and characterization of condensation by using analytical methods (Pressure Transient Analysis, PVT and production data analysis) The evaluation of various condensate recovery options (CO 2 , N 2 , separator gas, water injection and cyclic gas injection) using very refined single well physics based models The evaluation of condensate recovery options using full field models adapted from these physics based models The economical evaluation of condensate recovery options The proposed road map for maturation of the most promising options It is concluded from the conducted study work that out of the various injection fluid options considered, CO2 injection is likely to be the most favorable. Moreover, initial economical screening appear to be promising for CO2 injection.

The Middle to Late Cretaceous Natih formation in Oman can be highly compressible and undergo large compaction during depletion. Significant reservoir compaction and surface subsidence has potential risks for fault reactivation, integrity of wells and surface facilities. Petroleum Development Oman produces oil and gas from the Natih formation in a number of fields within its concession area. There are existing experiences in one of the analogue field in Oman, where the compaction of Natih formation has resulted in issues of well damage, well integrity, subsidence damage to facilities and experiences of surface tremors due to fault reactivation. The focus of this work was for Fahud West oil field producing oil and gas from a Natih reservoir, where analysis of an analogue field had indicated a high potential impact of compaction. A Geomechanical assessment of the formation within the field was therefore undertaken to mitigate operational risks, and to assess the permeability impact with increased depletion. The Integrated Geomechanical data acquisition and modeling minimized uncertainty and provided clarity on whether the reservoir can continue with increased depletion – without increased geomechanical risks of loss of integrity for wells and facilities, cap rock integrity or reduced productivity. Properly planned and rock mechanics measurements were conducted in the laboratory on core samples. The measurements revealed that the expected compaction of Natih reservoir in Fahud West field is less severe compared to the analogue field. The maximum predicted surface subsidence expected at depleted reservoir pressure of 10 bars, is within the tolerable subsidence limit for surface facilities. In addition, permeability measurements showed that the permeability at reservoir pressure of 22 bars (the previous base case for end of production), will not change significantly with further depletion of reservoir pressure to as low as 10 bars. The outcome of this integrated geomechanical assessment demonstrates that the field can be produced down to 10 bars from the previously estimated 22 bars (base case) limit, adding significant risked volume of oil production, allowing further drilling of wells to raise the final field recovery while ensuring safe well and facility integrity

One of the PDO's largest producing fields in Oman consists of three stacked reservoir formations, two of which are currently producing while deeper reservoirs are being considered for development. The shallowest reservoir (~ 900 m depth) is a highly compacting carbonate gas reservoir under depletion, whereas the intermediate reservoir Shuaiba is an oil-bearing reservoir under water flood. The deeper reservoirs are oil and gas bearing located in the Sudair and Khuff formations. Interpretation of 3D seismic data shows a major NE/SW and NW/SE fault system in all 3 reservoirs. Depletion in the shallow gas reservoir, which exhibits pore collapsing response on depletion, has induced surface subsidence which is active and expected to reach about 2.4 m at the end of field life. Subsurface deformations and induced stress changes have resulted in subset of the faults (NE/SW) to reactivate, causing seismic tremors, occasionally felt at surface. Ongoing surface subsidence has resulted in some damage to surface facilities and subsurface well integrity issues. Furthermore, fault reactivation and/or loss of well integrity may induce leakage pathways for reservoir fluids to cross flow between reservoirs or to shallow aquifers. PDO has implemented an extensive monitoring program supported by parallel 3D geomechanical modeling studies, to manage ongoing field development whist mitigating the risks. Extensive monitoring efforts using a variety of techniques are in place since 1999. Frequent InSAR satellite data measures surface subsidence with such high accuracy and resolution that local zones of higher deformation can be reliably identified and flagged. Continuous GPS data acquisition in a few places throughout the field allows for detailed temporal assessment of subsidence and forms the basis for predictions of total subsidence at end of field life. Periodic in-well compaction monitoring data provides insights in elastic and non-elastic deformation at reservoir layer scale, which is compared against core compressibility data. Continuous microseismic monitoring in a dozen or more observation wells highlights geomechanically active faults in the main reservoir, overburden and underburden, thereby identifying potential risk zones on a near-24/7 basis. All of this data is used both for well and facilities management, and for providing calibration data for geomechanical models. Results provide clarity on future surface subsidence and differential settlement, which helps to identify facilities with potential risk. The project teams are provided with reliable predictions of surface subsidence throughout the field to ensure the current design tolerance is adequate for integrity of the facilities until the end of field life. This paper presents modeling workflow and calibration with monitoring data related to the geomechanical assessment.

Specifically selected and manufactured organic fibres were used to bridge microfractures and stabilize shale and mudstone formations while drilling the Fiqa, Shilaif, Mishrif, Maddud and Nahr Umr formations and during a 5-day logging interval at the Mishrif formation. A newly developed method for testing invasion depth in 20/40 gravel pack sand, in order to monitor the fluids' bridging capability, was developed for drilling and logging the unstable Middle Cretaceous formations. The information from the tests was actively used to monitor and maintain the concentration of organic fibre materials in the drilling fluid to reduce invasion and to stabilise the highly fractured and layered shale and mudstone. A treatment programme was established around the data collected, using drilling fluids from the active system with a high concentration of fibres which was streamed back into the active system accordingly. The depletion rate was recorded and compared with the various formations during drilling. The drilling fluid chosen for the project was a water-based system, with 14% NaCl to balance the activity (AW) and formulated with a polyamine clay inhibitor. The section was planned with an extensive logging program in the Mishrif formation. Drilling had to be slow and controlled for parts of the Nahr Umr formation to pick the casing setting point in top Shuaiba formation. The hard and brittle shales found in this group of formations have been problematic for drilling in the Arabian Peninsula for a long time. The Nahr Umr formation is particularly known for its loose structure and frequent hole collapses which are caused by fluid penetration along pre-existing fractures and laminated surfaces. Oil-based drilling fluids are the preferred systems of choice to reduce the capillary effect of invading fluids, and the consensus is to reduce the exposure time for the formations as much as possible. As a water-based drilling fluid was chosen, a program was set up to focus primarily on a rapid build-up of a filter cake to bridge fractures and reduce filtrate invasion. The chosen organic fibres are anionic in nature and therefore have an affinity to the broken edges of clay platelets with a proven ability to create a network with particles that bridge the formation. The 12 ¼" section was drilled without stability issues and without remedial back reaming to the logging depth. The top part of the 12 ¼" section was kept open for 5 days during logging. The Nahr Umr formation was drilled with a controlled, low ROP to identify the setting depth for the 9 5/8" casing in top Shuaiba formation. Total open hole time was 4 days after logging. The casing was cemented without losses or other operational issues. The use of specific organic fibres to stabilise highly fractured shale formations presents a low cost and efficient method for dealing with a high-cost problem associated with significant NPT. Real time data collection and close monitoring of the fluids bridging capability using a fluid-invasion test kit proved to be an effective method for responding quickly to changes in hole stability, formation strength/integrity and fluid invasion. A quick mix and bleed method of additions based on the data collected is presented as a key finding. The novel treatment programme is shown to give practicing engineers a system and toolkit that works when dealing with the known problems associated with the Nahr Umr shale formation.

When a reservoir undergoes gas cap production without proper pressure maintenance, the underlying oil rim development at a later stage of the field development is very critical and challenging. Adding to the complexity is the tilted Free Water Level. This paper presents a study that was performed to model a large tilted oil rim reservoir that had been massively depleted by the production of the overlaying gas cap. The first part of the paper explains the development history of the oil rim and the low recovery factor that was obtained as a result of the massive gas cap depletion, and the results of previous attempts to revive dead oil wells through artificial means (ESP, booster pumps) which had limited success so far. The second part of the paper elaborates on the study which was carried out to build the concept of a tilted reservoir and later modelled it to get the proper initial water saturation distribution. The variable salinity concept was brought in to validate the proposed tilting scenario. The variable salinity was supported by produced water salinity data. The formation pressure test data also conforms to the tilting concept. The tilting in Free Water level (FWL) was also observed while analyzing capillary pressure data. Model was prepared to map the tilted FWL by krigging FWL depths at individual wells. The challenges that were encountered and overcome during the feasibility study: (1) construction of a new reservoir model incorporating a large set of static and dynamic data showing significant complexity with tilted fluid contacts, variable formation water salinity and initial fluid saturation; (2) multi-scenarios history matching with complex fluid movements and tilted Free Water Level; (3) reservoir uncertainty analysis using learnings from history matching; (4) accurate remaining oil saturation in oil rim. The originality of this study resides in the complex reservoir geology and field production history, in the integrated approach to address requirements of both oil rim and gas cap developments, and in the fact that proposed field revitalization calls for unusual static and dynamic reservoir property modelling which can conceptualize the fluid movement before and after production.

One of the principle inputs to project economics and all business decisions is a realistic production forecast. This becomes particularly challenging in supergiant oil fields with medium to low lateral connectivity. In this case, three distinct production forecasts were generated: Short Term (ST) – 3 months Medium Term (MT) – 2 years Long Term (LT) – 5+ years The main objectives of the Medium Term Production Forecast (MTPF) are: Provide an overview of the total expected production profile, expected wells potential/ spare capacity Highlight the requirements to maintain production targets Provide an anchor point for the ST and LT production forecast generation The main tool used for MTPF was Integrated Production System model or IPSM (GAP © PETEX) since it can predict reservoir behavior, honor physical constraints and capture bottlenecks and back-pressure effects within the production system. The different components of the IPSM are the reservoir component, well component and surface network. This paper covers the methodology for building the reservoir component of the IPSM to evaluate and accurately predict reservoir performance in the MT period. The IPSM model is not only used for the MTPF generation, but also for real time Production System Optimization (PSO), key decisions regarding well hookups, etc. by the Well, Reservoir and Facility Management (WRFM) team. There was a business need to build a pragmatic IPSM model with an optimal run time. Thus, tank models were built to replicate the 3D reservoir models which had been built in MoRes™ (dynamic reservoir simulator developed by Shell). The MoRes™ model was divided into multiple sectors (tanks) based on pressure sinks predicted by the model and supported by geological studies. From the MoRes™ model, a Grid cell Pressure histogram (Pressure versus frequency plot) was used to divide the reservoir into certain sectors. A close-to-normal distribution per sector was obtained to divide the reservoir into an optimal number of representative sectors. This was done because a single pressure value per sector is used by the well models connected to the sector to calculate the inflow performance in IPSM. Acquired Static Bottom Hole Pressures (SBHPs) in wells were used as anchor points for the calculated average pressure of the sectors and to test the validity of the divided sectors. This methodology has been tested successfully in the stated super giant oil field, which has both sandstone and carbonate reservoirs. An example this is covered in the paper. It was concluded that utilizing multiple sectors (tanks) results in reservoir pressure decline predicted being closer to what is actually seen by the wells. The IPSM model built represents reality sufficiently well in the MT period, thus increasing confidence in the generated production forecast. Another technical advantage of the described method is the higher sustainability of the model. The suggested histogram method, in combination with geological information available, can be applied to majority of the reservoirs. This combination is paramount to ensure the divided sectors concur with reality.

One of the largest gas fields in the Sultanate of Oman was developed between 2010 and 2016 by drilling 26 vertical wells for commingled production from three deep tight gas sandstone stacked reservoirs. The shallower reservoir is a rich gas condensate reservoir, while the other two contain lean gas fluids. Over the last few years, the wells performance has been poorer than anticipated. An integrated study was carried out in 2016-2017 to identify the root causes of this under performance and eventually address it in a new field development plan. All subsurface and surface disciplines worked together analyzing available data in order to understand the production behaviour and complex nature of the field. One of the major findings of the integrated study was the interpreted presence of sub-seismic lineaments corresponding to possible zones of quartz sealed fractures. This was supported by seismic, core, reservoir pressure (MDT) and pressure build up data. The integrated data analysis revealed that these lineaments are having a direct impact on the field performance, as the hydrocarbon in-place volume seen by each well is dependent on the compartments defined by these lineament boundaries. A large set of lineaments were added to the dynamic model after mapping from detailed seismic work. This addition resulted in very good matches of historical production and pressure data. These updates to the reservoir model will ensure a more accurate field forecast and provide a better field development strategy. This paper will demonstrate that the presence of sealed sub-seismic fractures that may remain undetected can have a substantial impact on the performance of tight gas reservoirs. By identifying these sub-seismic elements and understanding their impact through an integrated approach, field performance can be better forecasted in order to account for the presence of these features.

Objective It is challenging to increase oil recovery from a reservoir with a thin oil rim and large gas cap after a long depletion of the gas cap. Gas or water breakthroughs are commonly seen and are responsible for disappointing oil recovery. The development becomes more challenging when resources are needed to control depletion and maintain reservoir pressure. This paper deals with challenges encountered in developing a thin oil rim and compares the recovery of the development scenarios. Methods, Procedures The field under study is an offshore Carbonate reservoir consisting of multiple stacked thin porous layers separated by less porous layers. The gas cap was developed first, as at that time the oil rim was only poorly understood, and its potential was not fully recognized. Oil development only started after a prolonged period of gas depletion. Post depletion, gas injection has been introduced to control the depletion and to permit further development of the oil rim. The process followed in this study is summarized as follows: Build a simulation model (static and dynamic) in order to simulate reservoir fluid movement due to periods of depletion or gas recycling. Locate zones of remaining oil for development and suggest development options for these zones. Sweet zones to increase condensate production are suggested. Compare hydrocarbon recovery for several development scenarios with different pressure support strategies (and well completions). Finally a post gas production scenario to develop oil rim is presented as a revival scenario for oil rim development. Results A representative fit for purpose sub-surface model to capture the high reservoir heterogeneities and the dynamic behavior was crucial. It is demonstrated that despite the challenges inherent in this reservoir, it will be possible to increase the oil recovery. A number of locations for new oil production wells are identified and these allow recovery of additional oil through sustainable production. Zones of high CGR in the reservoir are a good target to enhance condensate production. For gas recovery reservoir pressure is the main factor controlling recovery. Novel/Additive Information This paper shows that despite the early depletion of the gas cap there is a room to enhance oil rim recovery of thin oil rim reservoirs underlying extensive gas caps, by means of a development which targets remaining oil, complemented by injection to control reservoir pressure depletion or Low well head pressure system to produce from low pressure reservoir. The post gas cap production scenario shows that theoretically there is an opportunity to recover oil after gas cap production.