Role Of Geomechanics Research Articles

Symposium Review: 3rd International Geomechanics Symposium gathers experts from around the world

The 3rd International Geomechanics Symposium (IGS2022) took place 7–10 November 2022 in Abu Dhabi. Focusing on the role of geomechanics in energy efficiency and sustainability, the technical program covered a range of technology applications including rock and in-situ stress characterization, natural fractures, faults, drilling, completion, stimulation, production, and reservoir engineering. It also showcased geomechanics applications in CO2 sequestration, hydrogen storage, and new energies.

Technology Focus: Mature Fields and Well Revitalization (January 2022)

The highlight of this year’s feature on mature fields and well revitalization has been the increasing use of artificial intelligence (AI) and machine learning (ML) for analysis of mature assets. Many paper proposals studied using AI/ML techniques cover a wide range of topics including optimization of production operations, faster reservoir characterization of mature fields, and improvement of ongoing waterfloods. In fact, increased use of AI/ML has been a recurring theme in many of the areas covered in the Technology Focus sections of 2021’s JPT issues. There has also been a focus on implementing novel technologies such as the use of autonomous inflow-control devices in horizontal wells to suppress ingress of unwanted fluids in thin-oil-rim reservoirs, using integrated-asset models for debottlenecking, and the use of cased-hole logging in old wells to look for missed opportunities. After serving for 5 years, my time for writing this column is coming to an end. It has been a highly rewarding exercise going through the paper proposals, experiencing the hard work put in by industry professionals to arrest inevitably declining production from mature assets by putting together ideas in diverse fields such as reservoir management, production optimization, drilling, and formation evaluation to produce the extra barrel from mature brownfields. Out of the 314 paper proposals studied in these 5 years, 137 (44%) dealt with waterflood improvement, reservoir characterization, and simulation, and approximately 78 papers (25%) dealt with well revitalization involving workover drilling, completion, and stimulation. Sustaining production from mature brownfields challenges the best from each discipline, and significant success stories have come from a genuine collaboration of ideas across disciplines from subsurface to engineering. Recommended additional reading at OnePetro: www.onepetro.org. SPE 206195 - Data-Driven Optimization of Intermittent Gas Production in Mature Fields Assisted by Deep Learning and a Population-Based Global Optimizer by Javier Fatou Gómez, TNO, et al. SPE 205546 - Role of Geomechanics in Identification of Possible Mechanisms for Nonproductive Time and Improving Drilling Operations in a Mature Field in Offshore Sarawak, Malaysia by Avirup Chatterjee, Baker Hughes, et al. SPE 206303 - Combining Capacitance Resistance Model With Geological Data for Large Reservoirs by Davud Davudov, Resermine, et al.

Revisiting field estimates for carbon dioxide storage in depleted shale gas reservoirs: The role of geomechanics

The prospects for CO2 sequestration in depleted shale gas formations are widely studied. Reported studies offer quantitative predictions of ultimate storage capacity as well as CO2 injection rate for a typical injection site or on an areal basis. Reported estimates for the ultimate storage capacity in various shales vary from 10 Gt to 50 Gt. In recent analysis, a numerical hydrodynamic model, neglecting geomechanical effects, was calibrated to historical gas field production data from various shales, and applied to estimate both injection capacity and rate. The projected site injection rates fell up to two orders-of-magnitude short of anticipated capture rates. It is hypothesized that geomechanical deformation, particularly within fractures, under depletion and pressurization can lead to significant variation in production and injection rates. This work revisits the field estimates by utilizing a coupled hydrodynamic and poromechanical model. History matching of field production data is performed using Ensemble Smoother with Multiple Data Assimilation (ES-MDA), and a Bayesian model-selection approach is applied. The results indicate that while both models are equally viable from the perspective of Bayesian model-selection, the coupled model estimates indicate a two-fold increase of capacity over those of the flow model. Moreover, the projected injection rates incorporating deformation are enhanced by two-folds at early times and by up to five-folds at later times.

In–Situ Dilation Affects Solvent–Assisted Steam–Assisted–Gravity–Drainage Performance: The Case of a Shallow Athabasca–Type Oil–Sands Reservoir

Summary It is generally accepted that solvent/steam injection in heavy-oil/bitumen reservoirs outperforms steam-only injection in terms of oil-recovery rate, ultimate oil recovery, and steam/oil ratio (SOR). Important parameters in the design of solvent-assisted steam-assisted-gravity-drainage (SA-SAGD) are solvent selection, injection strategy, and solvent retention in situ. The role of geomechanics in optimal application of SA-SAGD, however, remains largely unexplored. Recent studies suggest that solvent transport, solvent-dilution effect, and the temperature distribution around the edge of the steam chamber have major control over SA-SAGD performance. In SA-SAGD, elevated temperature and solvent concentrations within a few meters of the steam-chamber edge reduce the virgin-oil viscosity, causing oil drainage. However, this is the same region where geomechanically induced volume changes alter porosity, permeability, and relative permeability profiles. These alterations could improve the convective-heat transfer and solvent dispersion into the cold bitumen zone, and could also enhance the drainage rate. Consequently, the solvent/oil-phase behavior, steam-chamber growth, and solvent retention and distribution will be affected. This chain of events could have an effect on optimal solvent selection and solvent/steam-injection scenarios. These geomechanical considerations are of particular interest for bitumen deposits, both oil sands and carbonates, where chemical, thermal, and fluid pressures can impose significant volume changes within the reservoir, especially in shallower, lower-confining-stress settings. The role of geomechanics in SA-SAGD was explored numerically by use of a sequentially coupled modeling approach with STARS (CMG 2015a) and FLAC (Itasca 2016). A 2D shallow-depth homogeneous-oil-sands-reservoir geomodel, with properties similar to the Underground Test Facility (UTF) Phase A project, was constructed (Edmunds et al. 1994). Studies were conducted at two scales: the edge of the steam chamber and the reservoir scale including underburden and overburden. The results of these numerical studies revealed that geomechanics considerations directly affect the optimal solvent-type selection and injection strategy during a high-pressure SA-SAGD process. These studies provide valuable direction for further detailed mechanistic studies (both numerically and experimentally) and provide valuable input to the challenges of optimizing SA-SAGD processes in oil sands.

Seismic correlated Mallik 3D gas hydrate distribution: Effect of geomechanics in non-homogeneous hydrate dissociation by depressurization

The delineation of the Mallik gas hydrate field has utilized extensive well logging and substantial 3D seismic testing and interpretation. This study explores the use of seismic data to quantify the areally heterogeneous gas hydrate distribution. The available Mallik 3D seismic data was compiled and compared/contrasted with available well log data from two adjacent wells. Based on the seismic information, two areally variable (i.e. non-homogeneous) scenarios for gas hydrate distributions are considered: Scenario I having the same initial total hydrate amount as our earlier model areally uniform (homogeneous) distribution, and Scenario II with significantly less overall total hydrate, but honouring the same relative distribution. The scenarios of variable gas hydrate distributions are used in dynamic simulations of the lower Mallik zone. Simulations of each were conducted with and without the role of geomechanics.In Scenario I, we observed multiple gas production peaks (which quite similar to 6 days production behaviour) with higher localized pressure pulses occurred due to strong gas hydrate heterogeneity. In Scenario II, this drastic change in gas production rate was not observed (due to faster pressure evolution in the reservoir). In both Scenarios, the overall reservoir gas production peak is delayed compared to the homogeneous case. This is further delayed by the role of geomechanics. More interestingly, all simulation cases show a very similar overall production trend. This is probably a unique for the Mallik gas hydrate production using single vertical well, including a gas production peak but terminating in a stabilized period of lower but significant gas production.With geomechanics, gas production in general and the gas production peak is shifted and delayed. The geomechanics effect is not purely compaction drive (as in conventional reservoirs, gas production increases with geomechanics). The simulations utilized two set of geomechanical parameters obtained from logs (dynamic parameters) and rocks testing (static parameters). Geomechanical responses based on dynamic parameters were essentially equivalent to simulations ignoring geomechanical effects. The geomechanics simulations indicate an essentially elastic reservoir response (i.e. no plastic failure) assuming a cased vertical well. The Mallik upper zone A and middle zone B are closer to the permafrost and nearer to plasticity limits should be explored.

Geomechanical impacts on flow in fractured reservoirs

Abstract Flow responses in fractured reservoirs are difficult to predict. Apparent success in predicting flow has been achieved by developing simple rules of thumb based on (i) alterations of effective stress associated with pore pressure changes or (ii) concepts about fracture aperture alterations due to stress changes. Here it is argued that the assumptions underlying these explanations of flow are flawed, as they are based on ideas about stress that are physically wrong. It may be that these simple ideas can be fitted to some observations, but their use in this fashion is highly risky. The role of geomechanics in fractured reservoirs is more complex than suggested by the simple rules of thumb, as illustrated by numerical simulations that demonstrate the occurrence of strong non-linear interactions between the fluids, the geomechanics of blocky systems, and thermal changes. The resulting movements within fractured rock masses can cause major alterations of the upscaled flow properties. Flow performance discrepancies that are often associated with the operation of fractured reservoirs can, and often should, be seen as a consequence of motions occurring within the fractured rock mass. The explanations developed here are phenomenologically correct, and are more holistic than existing simple rules of thumb, improving the reliability of predictions.

Role of Geomechanics in Assessing the Feasibility of CO2 Sequestration in Depleted Hydrocarbon Sandstone Reservoirs

Carbon dioxide (CO2) sequestration in depleted sandstone hydrocarbon reservoirs could be complicated by a number of geomechanical problems associated with well drilling, completions, and CO2 injection. The initial production of hydrocarbons (gas or oil) and the resulting pressure depletion as well as associated reduction in horizontal stresses (e.g., fracture gradient) narrow the operational drilling mud weight window, which could exacerbate wellbore instabilities while infill drilling. Well completions (casing, liners, etc.) may experience solids flowback to the injector wells when injection is interrupted due to CO2 supply or during required system maintenance. CO2 injection alters the pressure and temperature in the near wellbore region, which could cause fault reactivation or thermal fracturing. In addition, the injection pressure may exceed the maximum sustainable storage pressure, and cause fracturing and fault reactivation within the reservoirs or bounding formations. A systematic approach has been developed for geomechanical assessments for CO2 storage in depleted reservoirs. The approach requires a robust field geomechanical model with its components derived from drilling and production data as well as from wireline logs of historical wells. This approach is described in detail in this paper together with a recent study on a depleted gas field in the North Sea considered for CO2 sequestration. The particular case study shows that there is a limitation on maximum allowable well inclinations, 45° if aligning with the maximum horizontal stress direction and 65° if aligning with the minimum horizontal stress direction, beyond which wellbore failure would become critical while drilling. Evaluation of sanding risks indicates no sand control installations would be needed for injector wells. Fracturing and faulting assessments confirm that the fracturing pressure of caprock is significantly higher than the planned CO2 injection and storage pressures for an ideal case, in which the total field horizontal stresses increase with the reservoir re-pressurization in a manner opposite to their reduction with the reservoir depletion. However, as the most pessimistic case of assuming the total horizontal stresses staying the same over the CO2 injection, faulting could be reactivated on a fault with the least favorable geometry once the reservoir pressure reaches approximately 7.7 MPa. In addition, the initial CO2 injection could lead to a high risk that a fault with a cohesion of less than 5.1 MPa could be activated due to the significant effect of reduced temperature on the field stresses around the injection site.

Role of Geomechanics in Appraising a Deep Tight Gas Reservoir: Amin Formation, Oman

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 142788, ’Role of Geomechanics in the Appraisal of a Deep Tight Gas Reservoir: A Case History From the Amin Formation in the Sultanate of Oman,’ by Satya Perumalla, SPE, Daniel Moos, Colleen Barton, SPE, and Thomas Finkbeiner, SPE, Baker Hughes; and Sultan Al-Mahruqy, SPE, Markus Weissenback, William Walton, SPE, and Hisham Al-Siyabi, Petroleum Development Oman, prepared for the 2011 SPE Middle East Unconventional Gas Conference and Exhibition, Muscat, Oman, 31 January- 2 February. The paper has not been peer reviewed. Overbalance leads to near-wellbore porosity and permeability damage in the rock matrix and fractures. Also, poroelastic effects caused by invasion contribute to difficulties in initiating and propagating hydraulic fractures. Damage to natural fractures intersecting the well can prevent their detection, leading to missed productive intervals. Alternatively, underbalanced drilling (UBD) can avoid these effects and, thereby, indicate the gas potential of these reservoirs better. However, not all reservoirs are suitable for UBD because there can be a greater risk of wellbore mechanical instability. Therefore, performing geomechanical analysis before drilling can help evaluate the feasibility of UBD operations. Introduction In North Oman, Petroleum Development Oman is exploring for gas in the Cambro-Ordovician Haima-supergroup Amin reservoir at depths of 4000+ m true vertical depth subsea. This formation is a tight sandstone, with porosity ranging from <3 to 10% and (ambient) permeabilities ranging from 0.001 to 1 md. Drilling exploration wells in this region is challenging because of the tight and abrasive nature of the formations and the large in-situ-stress magnitudes—high horizontal compression—that prevail in North Oman. Proving the existence and mobility of hydrocarbon gas, especially at commercial rates, may depend on wells intersecting a natural-fracture system that is permeable enough and is connected to a sufficiently large volume of reservoir rock and on the near-wellbore region of the reservoir not experiencing irreversible damage by drilling overbalanced. In light of these challenges, the decision was made, for an upcoming exploration well targeting the Amin formation, to drill a deviated well to maximize potential from the natural-fracture network and to drill in underbalanced mode to avoid invasion and to characterize any produced reservoir fluids. To understand the risks better before and during the drilling campaign, a geomechanics study was commissioned to support well planning and reservoir characterization in a phased approach. Exploration-Well Planning Stage It was important, while planning the vertical exploration well, to consider the structural uncertainties with seismic imaging of the Amin reservoir and to keep the well as far away as possible from any mapped major faults. To explore for open fractures in the Amin formation with a highly deviated sidetrack, the surface location of the vertical pilot hole was placed such that the planned sidetrack trajectory within the Amin reservoir could be drilled through the zone perceived as the most fractured on the basis of seismic-attribute interpretation.

Some geomechanical aspects of geological CO2 sequestration

Reservoir depletion and subsequent CO2 injection into the depleted geological reservoir induce stress changes that may mechanically damage top seal and wells, or trigger existing faults, creating the leakage pathways for CO2 escape from the reservoir. The role of geomechanics is to assess the mechanical impact of stress changes on seals, wells and faults. Since many hydrocarbon fields are geometrically complex and irregular, and the rock properties are spatially variable, such an assessment can be conveniently done with a numerical modeling of the field. Based on numerical analyses, recommendations can be given regarding the overall suitability of the depleted geological reservoir for CO2 disposal and safe CO2 injection.

The role of geomechanics in integrated reservoir modeling

The past decade has witnessed renewed interest and significant development in the field of reservoir geomechanics. Prior to that, geomechanics was a loosely collected group of applications of rock, soil, and fracture mechanics that addressed various problems in drilling, production, completion, and reservoir engineering. However, it is now increasingly evident that geomechanics is one of the common threads that connect many engineering disciplines that are essential for finding and producing hydrocarbon resources.

Discussion of "SAGD and Geomechanics"

Introduction As a researcher studying the role of geomechanics in the SAGD Process, it was great to read Mr. Carlson's Distinguished Authors Series paper entitled. "SAGD and Geomechanics" in the June 2003 issue of the JCPT. In response to this paper the following sections provide a discussion on SAGD-geomechanical issues raised by Mr. Carlson and presents additional observations concerning the role geomechanics my play ill the SAGD process. Particulate Nature of Oil Sands Due to the particulate nature of oil sands, its volumetric behaviour will differ depending on the loading conditions. When oil sand material is subjected to isotropic loading (Stress change equal in all directions), individual particles will generally deform in an elastic manner, with the possibility of grain crushing at high stresses, but the bulk mass of oil sands will undergo both elastic and irreversible volumetric changes with little re-orientation of the grains relative to each other. Figure 1 provides the nature of this isotropic loading relationship for oil sands and is generally similar to the conventional reservoir engineering approach to rock compressibility. When oil sands are subjected to shear Stress loading (non- isotropic or anisotropic), individual groins also deform elastically but grain crushing can become more prominent. With respect to the volume change behaviour all the mechanisms outlined in the "Interlocked Structure" section of the paper can occur. The main difference with isotropic loading, however is that shear loading can result in substantial re-orientation of the grains relative to each other. The result is that the pore volume shape and distribution (and by association, the permeability) under these loading conditions can be quite different. During the SAGD process, both isotropic and shear stress loading occur simultaneously. In the SAGD process, saturated steam with high pressure and temperature is continuously injected into the reservoir. Steam injection pressure results in in increase of pore pressure. So, effective stress is decreased and clastic deformation (expansion) occurs, which is the result of isotropic unloading. In a certain distance ahead of the.steam chamber surface, total stress increases due to the thermal expansion of the oil sand material inside the steam chamber. This Stress increase is anisotropic and shearing will probably occur in this area. Clearly the impact of porosity changes due to these two geomechanical mechanisms will create different pore geometry and it seems reasonable to expect that they will influence reservoir properties such as absolute permeability differently(1). The issue of grain crushing should also not be overlooked. Oil sand grains consist of different minerals. If the hardness of these minerals is high enough grain crushing may not occur. In contrast, if these minerals are relatively weaker, grain crushing can be an issue and must be taken into account when treating the reservoir permeability variations. For example. oil sands in the Athabasca deposit arc predominantly line 10 medium grained and uniformly graded sand whose mineralogy consists of approximately 95% quartz, 2% to 3% feldspar grains, 2% to 3% mica and clay minerals, and traces of other minerals(2,3).

The role of geomechanics in the construction phase of a major tunnelling project : Bennet, AG 5F,1T,11R. Paper to Design and Construction of Tunnels and Shafts Conference Melbourne, Aug. 1976, P65–74

The role of geomechanics in the construction phase of a major tunnelling project : Bennet, AG 5F,1T,11R. Paper to Design and Construction of Tunnels and Shafts Conference Melbourne, Aug. 1976, P65–74