Maintaining wellbore stable is one of the key tasks in the oil and gas industry, in order to reduce nonproductive time during drilling, because wellbore instability problems would lead to higher than necessary drilling costs and have a severe impact on drilling schedule. Wellbore stability is controlled by two type of factors, one type is the factors which are completely out of our control, such as in-situ stresses, pore pressure, and rock strength, the other type is the factors which we can optimize and design to minimize geomechanical related stability problems, such as well trajectory, casing seats, mud system, mud weight, and proper drilling practice including minimizing swab and surge while running pipe and reducing the stationary time during connection.In this paper, only the mud weight optimization and casing seats design will be focused on, in order to avoid geomechanical related instability issues for drilling a recently planned appraisal well in an offshore field.Mechanical properties including Young's modulus, Poisson's ratio, USC, friction angle, tensile strength, bulk density and pore pressure gradient obtained from two offset wells A1 and A2 were projected to the planned appraisal well A3 with tops were used as guidance. The same parameters optimized from those two offset wells were used to estimate horizontal stresses for the planned well, and the same failure criterion was used to carry out wellbore stability for the planned well. Meanwhile the mud weight corresponding to kick, breakout, loses and breakdown were obtained. Based on those results, the safe mud weight window was established and the casing seats were placed to prevent and reduce the geomechanics related instability problems.This methodology allows us to predict and prevent the geomechanics related instability issues in advance before drilling starts, thereby to reduce the non-productive time and drilling costs. Continuous updating of the geomechanical model is necessary during drilling if the geological environment is complicated.

ADMA-OPCO has undertaken a prestigious campaign to drill a large number of wells from artificial island in ABC field, most of these wells are extended reach drilling (ERD) wells with step-out up to around 18,000 ft. Operational efficiency/costs for drilling ERD wells is highly dependent on the wellbore stability, especially while drilling through the problematic Nahr Umr shale at different deviations and azimuths. Nahr Umr shale has a known history of causing wellbore instability in UAE and the surrounding countries and therefore a geomechanical study was initiated to understand the geomechanical setting in ABC field as well as fluid-rock interaction between drilling fluid and Nahr Umr shale formation. The main objectives of this geomechanical study were to optimize well design and drilling fluids in order to drill through Nahr Umr shale interval efficiently, additionally estimation of sustainable pressure variation that major faults can take without being reactivated was also performed. An integrated geomechanical study including a 3D geomechanical modeling was carried out, in order to ensure drilling through Nahr Umr shale formation efficiently. This study covered formation petrophysical characterization, chemical tests on cuttings from Nahr Umr shale, chemo-poroelastic modeling, weak bedding analysis and also faults reactivation analysis. Based on the study mentioned above, both customized drilling fluids program and suitable mud weights were optimized to stabilize Nahr Umr shale, and mitigate different types of wellbore instability issues. In addition to mud fluid optimization, the sustainable pore pressure variation was also estimated for several major faults. A successful drilling campaign is in progress; so far many deviated wells have been completed without any noticeable troubles while drilling through Nahr Umr shale. This geomechanical model is helping to implement an effective drilling program for a smooth well placement. A learning curve has been building up continuously for handling more complex well trajectories successfully in the future. From this study, it was realized that, not only fluid-rock interaction and geomechanics related factors need to be taken into consideration for stabilizing a wellbore, but also special attention is needed for the existing micro-fractures within the formation, where increase in mud weight may make hole condition worse. A balanced approach has been adopted including drilling fluid optimization in order to avoid possible multiple failure mechanisms.

A green field offshore Abu Dhabi is planned to be developed with miscible crestal gas injection and peripheral water injection scheme. Close to 100 slanted and horizontal wells (single in dual/triple Reservoirs) will be drilled from 2 artificial islands targeting four Upper Jurassic carbonate Reservoirs. Risks appear in developing the field due to the uncertainties related to complex faults and fractures network, carbonate reservoirs heterogeneity, Tar Mat, sour fluid production, and high departure wells. This paper illustrates full field development plan optimization studies that were conducted on a green field. The main objective of those studies was managing the reservoir uncertainties to enhance the full field development plans. 3D seismic, detailed sedimentological study, identified Reservoir rock types, Reservoir fluid characterization (Equations of state) and special core analysis (SCAL) using data collected from limited available wells were comprehensively evaluated and integrated to the input data of a 3D dynamic reservoir model.In order to achieve the studies objectives, number of parameters were addressed and optimized during assess and select phases of the full field development plan. These parameters are miscible and/or immiscible Gas injection scheme, peripheral Water Injection, Gas Injection timing and balance (standalone field development), and well locations based on structural and sedimentological uncertainties. Integration of static and dynamic data supported the development plan optimization to address the high uncertainty of the targeted Reservoirs. In addition, several sensitivity studies have been conducted for the reservoir uncertainty parameter ranges to understand their impact on the full field development plan.

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 Ko=0 to hydrostatic Ko=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 Ko, 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.