EAGE Workshop on Geomechanics in the Oil and Gas Industry

Succesful hydraulic fracturing is critical to develop Keshen HPHT tight gas reservoir located in Tarim Basin, Western China. Understanding of geomechanical properties in the Keshen reservoir provides essential input to optimization of hydraulic fracturing. Under HPHT environment, the mechanical properties of the reservoir rock exhibits very different mechanical behavior. To this end, a comprehensive laboratory testing program was performed to investigate the mechanical behavior of the sandstone of the reservoir rock when subjected to realistic in-situ stresses, pore pressures and temperature. The triaxial tests not only provided measurements on reservoir mechanical properties such as the Young’s modulus, Poisson’s ratio, rock strength, but also revealed their dependence on confine stress and temperature. Pore volume compressibility tests measured the pore volume compressibility and porosity reduction with depletion of the reservoir that is important for estimation of compaction drive of the reservoir. Since Biot elastic constant is essential to estimate effective stress state in the reservoir, two testing methods were devoted to measure it, one is through pair drained and undrained compaction tests from twin samples, and the other is the pore volume compressibility tests. Proppant embedment tests revealed the stress sensitivity of the propped fractures and potential embedment of proppant on the fracture surface. Based on the core test results, 1D mechanical earth models were constructed for the wells in the field. The reliability of the MEM was validated through comparison between wellbore stability predictions with observation of borehole failure from the microresistivity image. The integrated understanding of the mechanical properties and in-situ stresses provided critical input of hydraulic fracturing design and execution. The paper provides the detail of laboratory test programme and results, explains the workflow for 1D mechanical earth model building, and highlights unique mechanical properties of the HPHT reservoir sandstone formation.

The study reviewed in this paper aimed at determining the maximum injection pressure, together with injector location, in order not to damage the cap rock sealing efficiency. A cross disciplinary workflow was set up, involving geoscientists, geomechanical engineers and reservoir engineers. It consists of four major steps 1. Determination of the initial sealing conditions and potential weak points of the structure 2. 1D MEM (Mechanical Earth Model) as a first estimate of the maximum injection pressure 3. Elastoplastic framework of the carbonate reservoir matrix 4. 3D MEM (Mechanical Earth Model) to refine the 1D MEM findings This workflow enabled us to identify two main weak points of the reservoir • The apex of the structure, were a maximum pressure increase was defined. As pressure can rapidly propagate in fractures and karst, this maximum pressure increase was imposed at any well location • The border faults, and as a consequence no injectors were located in the vicinity of these faults and reservoir models were checked to ensure that no pressure increase would happen at these locations.

We introduce a novel approach to measure directly the formation pore pressure and temperature during injection and production operations. We analyze a set of acquired data and compare with conventional injection operation data. Through a system identification algorithm, we process the raw data and remove noise from the data. The overall result shows that the novel sensor technology applied provide the direct and reliable measurements of formation pore pressure and temperature.

The geomechanics community in the industry has generally adopted two different approaches to build geomechanical models: (1) determining subsurface horizontal stresses from acoustic dipole logs acquired at sonic frequencies and requires detectable amount of shear wave anisotropy; this approach produces rapidly varying stress profiles reflecting changes between and also within different lithological units. (2) Observation of stress-induced borehole failures (borehole breakouts or tensile fractures) and constrains horizontal stresses at discrete depth points; stress profiles are then extrapolated over the depth intervals of interest generally resulting in smooth horizontal stress profiles without appreciable variations across lithological boundaries. Each approach has its benefits and limitations and depending on the application and also the (service) provider utilized for geomechanics one model is preferred over the other. To better understand and compare results for the two approaches outlined above, OMV Austria Exploration and Production GmbH (OMV) commissioned two service providers with the scope to build a geomechanical model for one of its fields located in the Vienna Basin with the request to utilize “state of the art” modeling technology. This model was then to be calibrated and verified with drilling experiences and wellbore failures/enlargements (detected from provided caliper and image logs).

Uncertainty in wellbore stability predictions largely depends on the quality of the calibrated geomechanical model which is based on the most relevant offset wells which are analysed regarding their log and measurement data in order to sufficiently reproduce drilling experience. This is a process generally well described but its results often depend on the interpretation of information and application of various engineering workflows. The here presented cases focus on reducing risks during drilling by: a) planning the acquisition of high quality data, especially of stress; b) estimating the collapse pressure based on failure, and on interpreting drilling experience for determining applicable safe mud windows addressing the various, and often competing, well objectives; c) identifying depth intervals where drilling is possible without losses although the mud weight is exceeding the minimum principal stress.

Explaining Anomalous Wellbore Instability Problems in Ghawar Khuff Reservoir Khan, Khaqan; Abdul Halim, Ab Hamid and Anazi, Hamoud Abstract Saudi Aramco is aggressively pursuing drilling horizontal and multilateral wells in Khuff and Pre-Khuff reservoirs in the Ghawar Field to enhance gas production. Due to production-induced decreasing reservoir pressures coupled with tight nature of the reservoir rock, majority of the new wells are attempted in the minimum horizontal stress direction and completed with multistage hydraulic fracturing treatments which provide improved lateral reservoir contact enabling higher production at sustained rates as well as help increase recovery with lesser number of wells. However, horizontal wells drilled in the minimum horizontal stress direction are somewhat more challenging due to prevailing stress conditions resulting from regional tectonic compression. The experience to date shows that some wells were drilled without major drilling difficulty while some other wells have experienced more drilling problems leading to severe stuck pipe events and tools lost in hole. As wellbore instability can result from a combination of geomechanics and drilling-related factors, a detailed study was performed to identify the nature of these problems and ascertain major controlling factors for this variable drilling experience to make future drilling operations safer and more efficient through recommendations based on a diagnostic analysis of the drilling problems in existing wells. Analysis of data suggests that borehole ovality (breakouts severity) is a key contributor to the drilling challenges but it is not the only cause of the difficulties experienced. Apart from bore hole ovality, rate of penetration (ROP), hole cleaning and tripping practices also play significant roles in the drilling process (Fig. 1). The study also indicates that borehole ovality varies spatially suggesting variable stress conditions in the field resulting from the interaction of tectonic compressions, rock heterogeneity, reservoir depletion and structural geometry. Based on understanding of geomechanics, stable mud weight window was identified to manage breakouts and differential sticking problems. The implementation of these findings helped to drill wells safely and achieving the planned target reservoir contact and rate.  

Drilling a new development well in a mature shallow water field, offshore Sarawak, Malaysia, is challenging. Reservoir depletion reduces the fracture gradient to a level such that drilling and cementing operations risk hydraulically fracturing the wellbore. To compound matters, intra-reservoir claystone sections are weak and require higher mud weights to maintain wellbore stability. As a result, the operational mud-weight window becomes very narrow or disappears, and drilling operations will be challenging. A geomechanical study was undertaken for the field to understand the evolution of the fracture gradient due to depletion of the multiple sandstone reservoirs, the drilling risks associated with the large amounts of depletion, and to quantify operational mud-weight windows. The study results showed that a tight drilling mud window exists through many of the depleted reservoirs, but these narrow mud-weight windows could be widened by casing off interim reservoirs that have undergone high depletion. The results were integrated with the managed pressure drilling and the well was successfully drilled. This paper describes the practical geomechanical workflow that assists in understanding the drilling challenges in the depleted reservoir. The integrated geomechanical study and managed pressure drilling practice provide a feasible approach to mitigate drilling risks and minimise drilling costs.

The Mauddud reservoir is a Late Cretaceous carbonate reservoir dominated by midramp packstones with an average permeability of approximately 30 md. The spatial distribution of initial porosity and permeability using classical geostatistical methods proved difficult to history match the production data of the Mauddud reservoir in north Kuwait’s Sabriya field. Structural restoration followed by geomechanical forward modeling were conducted to obtain representative 3D porosity and permeability distributions prior to production. By performing coupled fluid-flow geomechanics simulations, the spatial and temporal variations of rock deformation, shearing, and dilation response can be reliably predicted. As a result, the change in porosity and permeability can be dynamically updated in the reservoir simulations, providing more realistic and accurate analysis of pressure and saturation distributions as a function of time within the reservoir. With pressure information and its progression rate and saturation, reservoir development decisions can be optimized with greater certainty and improved recovery factor. Structural restoration “back-stripping” modeling was performed to describe the structural evolution through geological time. Geomechanical forward modeling in geological time was performed and the results were validated with log measurements in the offset wells. Based on the geomechanical forward-modeling results, an initial porosity distribution was obtained for the reservoir

In many cases reservoir fluid flow simulations are performed on individual reservoirs, where there is assumed to be no interaction between adjacent reservoir. Geomechanically, the depletion and/or injection of an adjacent reservoir can have considerable influence on the stress state of the reservoir of interest, and therefore potential stability issues such as cap rock integrity, wellbore stability and fault reactivation. Before now, it has been very difficult to perform a single coupled geomechanical simulation incorporating the simultaneous production of a stacked reservoir system; recent developments in Reservoir Geomechanical Modeling now enables 2 way coupling modeling with multiple way coupling, using a single unified reservoir simulation model.