As active oil reservoirs mature, marginal fields development and management is becoming increasingly important.
Early identification of high degree reservoir heterogeneity served as starting point for an in-depth analysis for both, geologist and reservoir engineer.
This paper describes complex approach applied during evaluation and development of marginal oil field "Is" located in Serbia (Pannonian Basin).
Effective transition from exploration to development took place in 3 stages.
I-stage: 1 exploration well drilled, detailed analysis (seismic, sedimentology, core, PVT) and interpretation (log, well-test). Identification of vertical heterogeneity led to detailed analysis, which resulted in local depositional environment theory. Integration of seismic attribute and sedimentological analysis results was done. Due to geological uncertainties several 3D models were done for STOIIP range estimation. Recovery factor range was estimated using statistical, analytical and simulation model approach.
II-stage: 1 exploration well and 1 development well drilling and detailed analysis update.
III-stage: drilling of 5 development wells and continuous update of geological and simulation models.
Major uncertainties identified during I-stage were regarding to: reservoir structure, vertical and lateral heterogeneity, major fault permeability and OWC depth. Additionally, existence of active aquifer affected recovery factor estimation range.
I-stage analysis showed that, depending on depositional environment 4 different rock types are presented by conglomerates, conglo-breccia, breccia and metamorphic rocks.
The target formation (conglomerates) were formed by proluvial fan. This deposits are characterized by an alternation of rhythms (fragment size and orientation, conglomerate size, terrigenous material sorting).
Proluvial fan boundaries were detected on the seismic attribute map.
Second exploration well location was a result of multidisciplinary analysis during I-stage. Well was successful and highly informative during II-stage as it proved oil saturation behind major fault, reduced previous STOIIP estimates and confirmed presence of active aquifer.
STOIIP and reservoir structure excluded possibilities for regular/typical well patterns, therefore each well location was carefully selected, while total well number was determined based on estimated recovery factor.
Complex multidisciplinary approach used during this project, can be an example for successful and effective marginal heterogeneous oil field development. Understanding the reasons for reservoir heterogeneity together with confident estimate of recovery factor, gave us success during each new well placement and total well number determination.
Gao, Jia Jia (Department of Civil & Environmental Engineering, National University of Singapore) | Lau, Hon Chung (Department of Civil & Environmental Engineering, National University of Singapore) | Sun, Jin (Institute of Deep-sea Science and Engineering, Chinese Academy of Sciences)
Conventional drilling design tends to inaccurately predict the mud density needed for borehole stability because it assumes that the porous medium is fully saturated with a single fluid while in actuality it may have two or more fluids.
This paper provides a new semi-analytical poroelastic solution for the case of an inclined borehole subjected to non-hydrostatic stresses in a porous medium saturated with two immiscible fluids, namely, water and gas. The new solution is obtained under plane strain condition. The wellbore loading is decomposed into axisymmetric and deviatoric cases. The time-dependent field variables are obtained by performing the inversion of the Laplace transforms. Based on the expansion of Laplace transform solution, we derive the unsaturated poroelastic asymptotic solutions for early times and for a small radial distance from an inclined wellbore. The model is verified by analytical solutions for the limiting case of a formation saturated with a single fluid. The impact of unsaturated poroelastic effect on pore pressure, stresses and borehole stability is investigated.
Our results show that the excess pore pressure due to the poroelastic effect is generally higher for the saturated case than the unsaturated case due to the large difference between the compressibility of fluid phases. The time-dependency of the poroelastic effect causes the safe mud pressure window of both the unsaturated and saturated cases to narrow with increasing time with the unsaturated case giving a narrower safe mud pressure window. Furthermore, this window narrows with increasing initial gas saturation. The commonly used assumption that the formation is fully saturated by one fluid tends to be conservative in predicting the mud density required for borehole stability.
This new semi-analytical poroelastic solution enables the drilling engineer to more accurately estimate the time-dependent stresses and the pore pressure around a borehole, thus allowing him to design the mud weight to ensure borehole stability.
Fluid flow in sedimentary rocks is controlled mainly by the morphology of pore-connecting throats. Pore throats (PTs) typically exhibit diverse converging/diverging morphologies such as biconic, parabolic, or hyperbolic geometries. These different geometries are defined by variable opening angle, or angularity, between the throat walls from the narrowest point of the throat toward the pore body. Importantly, each of these geometries imposes different constraints on fluid flow. However, current pore-level flow models usually favor simple cylindrical or biconic throat morphologies, in part because of the difficulty to extract the throat angularity from pore-space imagery. An image-analysis technique called mathematical morphology has been used to characterize porosity in laterally continuous pore networks (e.g., in sandstones) from thin-section microphotographs. This method allows the extraction of petrophysical parameters such as pore and throat diameters through successive image alterations—namely, erosion/dilation cycles using an expanding structuring element (SE). This study proposes a novel application of this technique and quantifies PT angularity. Angularity can be measured from the throat toward the pore body so that the true geometry—biconic, parabolic, or hyperbolic—can be recognized. The technique is tested on simple geometries to demonstrate the correctness of the mathematic equations involved. Because all equations assume perfect, nonpixelated geometries while images are composed of square pixels, the accuracy of measurements depends strongly on image resolution. Pixelation causes significant fluctuations of ±2 to 10° around the correct angularity values that decrease in amplitude as image resolution increases. Finally, potential implications of this parameter on fluid-flow modeling are discussed.
Chung, Traiwit (University of New South Wales) | Wang, Ying Da (University of New South Wales) | Armstrong, Ryan T. (University of New South Wales) | Mostaghimi, Peyman (University of New South Wales)
Direct simulation of flow on microcomputed-tomography (micro-CT) images of rocks is widely used for the calculation of permeability. However, direct numerical methods are computationally demanding. A rapid and robust method is proposed to solve the elliptic flow equation. Segmented micro-CT images are used for the calculation of local conductivity in each voxel. The elliptic flow equation is then solved on the images using the finite-volume method. The numerical method is optimized in terms of memory usage using sparse matrix modules to eliminate memory overhead associated with both the inherent sparsity of the finite-volume two-point flux-approximation (TPFA) method, and the presence of zero conductivity for impermeable grain cells. The estimated permeabilities for a number of sandstone and carbonate micro-CT images are compared against estimation of other solvers, and results show a difference of approximately 11%. However, the computational time is 80% lower. Local conductivity can furthermore be assigned directly into matrix voxels without a loss in generality, hence allowing the pore-scale finite-volume solver (PFVS) to be able to solve for flow in a permeable matrix as well as open pore space. This has been developed to include the effect of microporosity in flow simulation.
The task of reliable characterization of complex reservoirs is tightly coupled to studying their microstructure at a variety of scales, which requires a departure from traditional petrophysical approaches and delving into the world of nanoscale. A promising method of representatively retaining a large volume of a rock sample while achieving nanoscale resolution is based on multiscale digital rock technology. The smallest scale of this approach is often realized in the form of working with several 3D focused-ion-beam–scanning-electron-microscopy (FIB-SEM) models, registration of these models to a greater volume of rock sample, and estimation and scaling up of model local properties to the volume of the entire sample. However, a justified and automated selection of representative regions for building FIB-SEM models poses a big challenge to a researcher. In this work, our objective was to integrate modern SEM and mineral-mapping technologies to drive a justified decision on location of representative zones for FIB-SEM analysis of a rock sample. The procedure is based on two experimental methods. The first method is automated mapping of sample surface area with the use of backscattered electrons (BSEs) and secondary electrons (SEs); this method has resolution down to nanometers and spatial coverage up to centimeters, also referred to as large-area high-resolution SEM imaging. The second method is automated quantitative mineralogy and petrography scanning that allows covering sample’s cross section with a mineral map, with resolution down to 1 µm/pixel. Data gathered with both methods on millimeter-sized cross sections of rock samples were registered and integrated in the paradigm of joint-data interpretation, augmented with computer-based image-processing techniques, to provide a reliable classification of nanoscale and microscale features on sample cross sections. The superimposed SEM and mineral-map images were combined with physics-based selection criteria for reasonable selection of FIB-SEM candidates out of a great number of potential sites. In the result, a semiautomated work flow was developed and tested. Demonstration of the work flow is made on one of Russia’s most promising tight gas formations, where the characteristic dimension of void-space objects spans from a single nanometer to millimeters. An example of an optimized site selection for FIB-SEM operations is discussed.
Tamayo-Mas, Elena (British Geological Survey) | Harrington, Jon (British Geological Survey) | Shao, Hua (Federal Institute for Geosciences and Natural Resources) | Dagher, Elias (Canadian Nuclear Safety Commission / University of Ottawa) | Lee, Jaewon (Korea Atomic Energy Research Institute) | Kim, Kunhwi (Lawrence Berkeley National Laboratory) | Rutqvist, Jonny (Lawrence Berkeley National Laboratory) | Lai, Shu-Hua (National Central University) | Chittenden, Neil (Quintessa Ltd.) | Wang, Yifeng (Sandia National Laboratories) | Damians, Ivan (Universitat Politecnica de Catalunya) | Olivella, Sebastia (Universitat Politecnica de Catalunya)
The processes governing the movement of repository gases through engineered barriers and argillaceous host rocks can be split into two components, (i) molecular diffusion (governed by Fick's Law) and (ii) bulk advection. In the case of a repository for radioactive waste, corrosion of metallic materials under anoxic conditions will lead to the formation of hydrogen. Radioactive decay of the waste and the radiolysis of water are additional source terms. If the rate of gas production exceeds the rate of gas diffusion within the pores of the barrier or host rock, a discrete gas phase will form (Wikramaratna et al., 1993; Ortiz et al., 2002; Weetjens and Sillen, 2006). Under these conditions, gas will continue to accumulate until its pressure becomes sufficiently large for it to enter the surrounding material. In clays and mudrocks, four primary phenomenological models describing gas flow can be defined, see Figure 1: (1) gas movement by diffusion and/or solution within interstitial fluids along prevailing hydraulic gradients; (2) gas flow in the original porosity of the fabric, commonly referred to as two-phase flow; (3) gas flow along localised dilatant pathways, which may or may not interact with the continuum stress field; and (4) gas fracturing of the rock similar to that performed during hydrocarbon stimulation exercises.
ABSTRACT: The estimation of the in-situ stress state is required for the design and execution of deep engineering operations related to Enhanced Geothermal System (EGS). Borehole failures, often referred as borehole breakouts, which are controlled by local stress concentration around the wellbore, are recognized being a useful indicator to assess in-situ stress conditions. However, breakouts evolve with time and this may affect our ability to use them for quantifying the stress state. We use a unique data set from the deep geothermal well of Rittershoffen GRT-1 in order to verify the hypothesis concerning wellbore breakout geometrical evolution. In GRT-1 wellbore, imaging has been acquired 4 days, 348 days and 946 days after drilling completion. Thermal, hydraulic and chemical stimulations have been performed between the first and the second image acquisition. Using this data set, we were able to describe in-situ the breakout evolution with time. We show increase in the extension of breakouts along the well. Contrary to the common assumptions, we also show that breakout widen, but within the limit of the accuracy of our analysis they do not deepen. The consequences of the breakout evolution for stress characterization are significant and add up to other important uncertainties in such analyses like the estimation of strength parameters.
A large amount of energy is available at depth. This energy can be extracted by circulating fluids between boreholes through the hot rock mass, but this requires that sufficient permeability is present at depth. As permeability tends to decrease with depth (Manning and Ingebritsen 1999), it is necessary to target deep structures with locally higher permeability (e.g. fault zones) and/or to perform permeability enhancement operations. The later approach is referred as Enhanced Geothermal Systems (EGS). The principle underlying this technology consists of increasing the hydraulic performance of the reservoir through different types of stimulations so that commercially interesting flow rate can be achieved. The stimulations consist of high-pressure injection (hydraulic stimulation), cold water injection (thermal stimulation) or chemical injection (chemical stimulation). In the two first cases, the permeability increase is obtained by inducing a thermohydromechanical perturbation to the rock mass which reactivates existing structures or create new ones. The in-situ stress state is central to understand the response of the rock mass to injections and to design such operations.
Dutler, N. O. (University of Neuchâtel) | Valley, B. (University of Neuchâtel) | Gischig, V. (CSD Engineers) | Jalali, M. R. (SCCER-SoE) | Doetsch, J. (SCCER-SoE) | Krietsch, H. (SCCER-SoE) | Villiger, L. (SCCER-SoE) | Amann, F. (Chair of Engineering Geology and Environmental Management)
ABSTRACT: Various in-situ hydraulic fracturing experiments were carried out in the naturally fractured, crystalline rock mass of the Grimsel Test Site (GTS) in Switzerland. The purpose was to study the geometry of the newly created fractures and their interaction with the preexisting fracture network using transient pressure and rock mass deformation observations. Under controlled conditions, six hydraulic fractures with similar injection protocols were executed in two sub-vertical injection boreholes. The rock mass is intersected by two E-W striking shear zones (S3), and two biotite-rich meta-basic dykes with a densely fractured zone in between. The S3 shear-zone intersecting the rock volume of interest acts as a high-permeability connection to the tunnel for the experiments executed south of it. Strong variation in injectivity enhancement, jacking pressure, break down pressure, instantaneous shut-in pressure and fluid flow recovery among the different injection intervals indicate different stress conditions north and south of S3.
The main requirement for extracting energy from the subsurface is sufficient fluid flow through permeable pathways to transport heat or oil/gas from the underground to a production well. The crustal permeability decreases with depth (Manning & Ingebritsen, 1999; Rutqvist & Stephansson, 2003), which influences the productivity in a negative manner. Thus, the permeability in deep target reservoirs has to be enhanced through hydraulic stimulation. Only by enhancing the permeability of the underground, sufficient conductivity and connectivity are achieved. Geothermal projects utilizing permeability enhancement techniques are referred as enhanced geothermal systems (EGS) (Cummings & Morris, 1979).
Two main processes are typically invoked during permeability enhancement: 1) hydraulic fracturing and 2) hydraulic shearing. Hydraulic fracturing is the initiation and propagation of tensile (mode I) fractures. It occurs when tensile stress exceeds tensile strength and the energy, which is required to create new surfaces in the rock exceeds fracture toughness (Detournay, 2016). When the stimulation operation is completed, the newly formed hydraulic fractures keep a residual aperture resulting in permeability enhancement (Jalali et al., 2018).
While permeability modeling follows a wellestablished approach in converting laboratory properties to subsurface conditions, ambiguity remains over the approach to be followed by laboratory-acquired capillary pressures (under ambient conditions, like most mercury injection capillary pressures (MICP) measurements). One approach (developed by the earlier work of Juhasz) recommends that capillary pressures be stress corrected (prior to modeling) according to a correlation. Another approach suggests the saturation-height model (SHM) be built with ambient measurements that when supplied with corrected properties (porosity and permeability) would generate in-situ saturations. The effect of stress correction applied to porosity and permeability data (as part of routine core analysis (RCA) is not easily compared against the capillary pressure correction, potentially leading to inconsistencies. The work presented here uses a recent methodology that aims at ensuring consistency between permeability and SHMs to provide guidance on the best approach to be followed in the process of building a SHM. The MICP or SHM carries an intrinsic permeability that can be compared to the permeability model. The results show that signicant inconsistency can occur between the porosity-permeability data (a reliable, well-controlled and measurable property under stress) on one hand, and the MICP-/SHM-inferred permeability on the other.
Cores can be considered the ground truth only if we eliminate or minimize their damage during the core cutting, tripping, and surface handling. Such damage would adversely alter their properties. An important source of core damage is during tripping when the quick decompression may cause damage due to the induced microfractures. In this paper, a state-of-the-art geomechanical model is introduced and applied for determining the safe tripping rates.
The Thermo-Poro-Elastic (T-P-E) geomechanical approach used in this study includes the mathematical derivation of the diffusion time required for the imposed pore pressure difference to dissipate while also considering the effects due to the temperature changes, the mud cake, and swabbing. The work utilizes different approaches for fluid modeling in a transient manner during tripping for the water-bearing, gas- bearing, and oil-bearing cores.
In this work, the hydraulic diffusivity and the fluid type have been introduced as the main factors controlling the maximum allowable safe tripping rates. A relationship between the allowable decompression rate and the hydraulic diffusivity will be presented for each specified fluid type. In addition, the results indicate that water-bearing cores can be safely tripped as quickly as the normal tripping speed of the wireline, even with core permeabilities of as low as 0.01 mD. For gas and oil-bearing cores, the safe tripping rates are determined to be much less than the water-bearing cores as the fluids expand with pressure drop along its journey to the surface. The results show that the tripping rate is the lowest for the oil-bearing cores particularly in the vicinity of the bubble point and gas critical pressure (as the gas expansion pushes the oil and applies significant viscous forces across the core pore throats).
This paper is a novel work developing T-P-E and mathematical models for the case of core tripping considering the effects of the pore pressure change, temperature change, the mud cake, and swabbing. The hydraulic diffusivity and the fluid type have been considered as the controlling factors. The approach has been applied for modeling the tripping of water, gas, and oil-bearing cores to provide maximum allowable tripping rates.