ABSTRACT: Understanding the fluid flow physics in porous media is essential to enhance reservoir management. Complexity associated with characterizing reservoir rocks and rock/fluid interactions is multifold. In the laboratory studies, especially repeated destructive experiments, the challenges of using real core-plugs include high acquiring cost, preserving to in-situ conditions, samples damage. Another challenge is the accurate characterization of uncertain pore network structure which is crucial in understanding the storage capacity and mass transport of fluids, especially in an EOR process and unconventional samples. Cheap 3D-printed core-plugs can help to avoid such problems with accurate 3d-printed pore network and with a uniform printing material which has a predictable fluid interaction. In this work, a new methodology is proposed to reconstruct the core-plugs’ CT-scan data to create representative 3D-printable porous replicas. Image processing tools were used to segment the grains and pores in CT-scan data. The processed segmented CT volume is then converted from grayscale images to a binarized continuous volume to be meshed in a 3D-printable format. Finally, synthetic samples were produced by using different base and binding materials (i.e. gypsum/sandstone and plastics). Acceptable measured petrophysical properties for each replica (e.g. porosity and permeability) match the understudy core-plug (Berea sandstone) properties.

ABSTRACT: In order to constrain the contribution of mechanical deformation to injectivity decline in an existing Gulf of Mexico (GoM) field, the hydromechanical behavior of the Castlegate sandstone was studied at close to in situ conditions of pressure and temperature with the goal of devising methods and expectations regarding further work on a waterflooded sandstone formation. In addition to the use of high temperature and pore pressure, the stress conditions for brittle failure were probed using pore pressure buildup as the driving force as opposed to conventional triaxial loading. Through a methodical analysis of the effects of thermal and mechanical loading on flow properties, we observe a very substantial loss of permeability during the attainment of in situ conditions before the initiation of the pore pressure buildup, with the potential of increasing permeability hindrance due to fines migration. Brittle failure during pore pressure buildup is associated with the formation of a thin dilatant shear fracture and moderate permeability reduction. Follow-up work will be aimed at realizing the integration between geomechanical modeling and reservoir core analysis in order to provide a comprehensive understanding of the physical mechanisms involved in waterflooding operations and formulate operational guidelines.

ABSTRACT: Slurry waste management may involve injection of solid-laden fluids with concentration up to 25%. To accomplish this without plugging the near wellbore pore space, a fracture is created first using a pad of clean fluid. In some cases, where the formation has a high permeability-thickness product, kh, high injection flow rate is needed to open up the fracture with clean fluids. Most disposal wells do not have large enough pumps to provide the needed flow rates. A combination of a lack of geomechanical understanding combined with poor injection or facility design leads some operators to create high formation damage around their wellbores in slurry injection applications by injecting slurry at flow rates which are insufficient to open fractures. Moreover, the damage causes injection pressure to build up rapidly, facilitating the creation of short fractures which tend to cause near wellbore stresses to increase more rapidly for a given amount of solid deposition than is the case with longer fractures. This paper presents one case study which evaluates the injection well using operational data.

ABSTRACT: Subsurface fluids that are super-saturated can influence the extent to which defective natural caprocks are sealed. The convective transport of such fluids are of interest in other to provide effective containment for sequestered CO 2 in targeted repositories. Fracture geometry largely govern fluid flow characteristics in deep micro-fractured formations, it has been postulated that the effect of mineralization can lead to flow impedance in the presence of favorable geochemical and thermodynamic conditions. Simulation results suggested that influx-induced mineral dissolution/precipitation reactions within clay-based sedimentary rocks can continuously close micro-fracture networks, though injection pressure and effective-stress transformation first rapidly expand the fractures. This experimental modelling research investigated the impact of in-situ geochemical precipitation on conductivity of fractures under carbon sequestration conditions. Geochemical analysis were performed on four samples of natural shale rocks, effluent fluids and recovered precipitates both before and after CO2-brine flooding at temperature and pressure conditions similar to that of the subsurface. Bulk rock geomechanical hardness was determined using Vickers’ micro-indentation. Differential pressure drop data across fractured composite core were also measured with respect to time over a five day period. This was used in estimating the conductivity of the artificially fractured cores. The estimates of 1 st order pressure derivative and dimensionless fracture conductivity indicated that reactive transport of dissolved minerals in aqueous fluids can occlude micro-fracture flow paths in naturally fractured shale rocks.

Abstract Produced water re-injection (PWRI) is often the safest and most economical method for disposal of produced water in the oil industry. Two key issues that affect the management of PWRI are the formation damage and the constrained pumping pressure at the wellhead. A simulator was developed to handle the design of single-zone or multi-zone water injection in multilayered reservoirs. The simulator can accommodate both vertical and horizontal wells operated under matrix and/or fractured regimes. It is also able to account for the impact of formation damage and user-defined wellhead pressure constraints. Results obtained from the simulator showed good agreement with known injection behaviors. For vertical wells, injection conformance depends on KH (permeability-thickness) and the minimum horizontal stress; in the case of multi-fractured horizontal wells, the outermost fractures (those near the tip and the heel of the horizontal well) are longer than the fractures in the middle. Lastly, by constraining the maximum allowable surface pressure, frictional pressure drops in both the wellbore and fracture cause the injection rate to decline, which in turn affects both the fracture geometry and the maximum disposal volumes.

Abstract Deep saline aquifers have a great potential for geologic carbon dioxide (CO 2 ) sequestration and proper assessment of host and cap rock is needed to guarantee that the procedure is safe. Temperatures and pressures at which most of the possible host rocks exist dictate that CO 2 is present in a supercritical condition, having both gas and liquid properties. Hence, rock-fluid interaction has to be studied and measurements of poroelastic parameters are necessary. Sandstone formations are mostly considered as the possible host rock. However, in some countries only calcite-rich formations can satisfy the requirements for safe geologic CO 2 sequestration. This paper deals with measurements of poroelastic parameters of calcarenite (or Apulian limestone), which is 95-98% calcite. Jacketed and unjacketed hydrostatic compression experiments and undrained plane strain compression tests provided the full set of poroelastic parameters. Additionally, the specific storage coefficient was calculated. Inability to obtain constant values of Skempton B coefficient even at high pore pressures (~ 4 MPa) and the decrease in P-wave velocity with water injection revealed partial dissolution of calcarenite in water at high pressures. This phenomenon, as well as the mechanical behavior of rock in contact with supercritical CO2, are currently under consideration.

Abstract We present a three dimensional fluid-structure coupling between SPH and 3D-DDA for modelling rock-fluid interactions. The Navier-Stokes equation is simulated using the SPH method and the motions of the blocks are tracked by a Lagrangian algorithm based on a newly developed, explicit, 3D-DDA formulation. The coupled model is employed to investigate the water entry of a sliding block and the resulting wave(s). The coupled SPH-DDA algorithm provides a promising computational tool to for modelling a variety of solid-fluid interaction problems in many potential applications in hydraulics, rock mass stability, and in coastal and offshore engineering.

ABSTRACT Understanding mechanisms of rock-fluid interaction is vital for enhanced production and compaction in chalk reservoirs. In order to investigate role of specific ions in sea water, as a common injector, combined rock mechanical tests with chemical analysis of effluents were performed on chalk outcrops. The experiments in this study supply additional information on chemical mechanisms in chalk water weakening taking into account only magnesium ion. According to the results, dissolution of chalk grains solely or together with precipitation should be consider in field of water weakening. The results also revealed importance of diffusion-transport phenomena and significance of flooding rate in experimental work on outcrops. INTRODUCTION Hydrocarbon production, mining activities, and ground water removal could create downward movement of Earth’s surface which is addressed as subsidence. This phenomenon has been received great attention in the field of hydrocarbon extractions. Reservoir compaction was detected for the first time in the Goose Creek oilfield located along the Texas gulf coast in the U.S.. Compaction of the Ekofisk field in Norwegian sector of the North Sea, as a costly case, was recognized and reported in the eighties and early nineties. The constituent reservoir rock of Ekofisk field is chalk, a mixture of intact and/or fragmentary skeletal debris (about 10 µm in diameter) produced by planktonic algae (coccoliths). Researchers have attempted to explain and predict the compaction issue in the chalk layers of Ekofisk field in terms of primary depletion and rock compressibility. Although water injection in the Ekofisk field was started in 1987 in order to improve oil recovery and maintain the average reservoir pressure, the subsidence is still persisting. In spite of oil displacement by water, the chalk immediately becomes weaker in presence of water, a phenomenon referred to as the water weakening effect of chalks. Therefore, several studies have been initiated in the area of chalkfluid interaction in order to investigate the sensitivity of chalks to water from a chemo-mechanical point of view. In most of these studies the effect of seawaterlike brines on chalks mechanical stability was investigated. However, the presence of several different types of ions in seawater-like brines makes chalk-fluid interactions complicated to analyze. The strategy in a series of study set out how aqueous solutions of common salts (NaCl, Na 2 SO 4 , MgCl 2 , and CaCl 2 ) could affect the mechanical strength of chalk. The present work focuses on effect of magnesium ions. Meanwhile, it is attempted to answer the question on rate dependence of fluid inside the core on mechanical behavior of the rock. Towards a comprehensive study on chalk-fluid interaction, this paper combines the result of rock mechanical tests, i.e. hydrostatic loading and timedependent behavior, with chemical analysis from sampled flooding effluent. Subsequently, a chemomechanical coupling in chalk is discussed in terms of different proposed chalk-fluid weakening mechanisms such as physical and/or chemical which are briefly reviewed. This study could contribute to the development of chemo-mechanical modeling of chalk.

ABSTRACT: Permanent instruments to measure pressure and temperature are a regular feature of oil and gas well completions. As wells are drilled in deepwater, high-pressure, high-temperature, high-porosity reservoirs or other challenging environments, these measurements provide valuable data to evaluate reservoir quality and wellbore integrity. Pressure data is routinely used to determine the flow properties of the reservoir with transient analysis. Key performance indicators (KPI?s) are selected by the well operator such as reservoir permeability, pressure, and formation damage index or skin factor; these KPI?s are archived and trended with time to identify production impairments and opportunities for well intervention. Aside from routine well production surveillance, the pressure history allows for assessment of geomechanical changes such as the degree of reservoir compaction and to evaluate the potential of wellbore failure due to compaction-induced displacements. This paper illustrates the use of the pressure and temperature data from a deepwater well completion in the Gulf of Mexico (GOM) to monitor compaction and to understand the possible mechanisms behind a sudden drop of production that took place in early 2007. 1. INTRODUCTION Oil and gas wells may be instrumented with several different sensors such as fiber optic cables, multi-phase flowmeters, or solids-monitoring devices. Although new measurements and new devices are continuously emerging, the instruments most likely to be found in a wellbore are the pressure and temperature gauges. Permanent pressure recorders have been installed in oil and gas wells for several years, some as early as 1963 as described by Nestlerode[1]. By 1978, ExxonMobil had installed their first permanent bottomhole pressure sensors[2]. In the decades since, the permanent pressure and temperature sensors have become a staple of offshore well installations. Efficient data handling, transmission and archive systems have evolved to ease the process of acquiring data for engineering analysis. Pressure and temperature data are collected and recorded every few seconds. Over the productive life of a well, this will result in gigabytes of data storage requirements. The oil and gas industry has established workflows for using these highfrequency data for production management concerns such as well stimulation[3], measuring reservoir depletion[4], and optimizing future well placement[5]. By following these workflows, engineers are able to efficiently transform the raw data into useful reservoir and production parameters and quickly take action on the well. One of the most common workflows is to use the pressure data and the transient response during a shut-in to determine the reservoir flow properties. Steady-state flow in a porous media is described by Darcy?s Law, which is given in Eq. (1). The transient analysis yields the data necessary for understanding the flow behavior: (available in full paper) Key parameters include the product of the reservoir permeability and its thickness, kh , the current reservoir pressure, P r , and a dimensionless formation damage indicator known as the skin factor, s. As each of these properties is dynamic, it is crucial to the production engineer to know how these properties are evolving with time in order to understand whether the well is performing at its full potential.

ABSTRACT: This paper discusses two elements of drilling-induced formation damage: damage caused by the stress alterations resulting when replacing the rock with a borehole fluid, and the damage caused by thermo-mechanical effects due to temperature variations. Results from laboratory tests are presented and discussed, together with theoretical calculations. Drilling-induced stress alterations may result in significant damage, damage which may enhance sand production. In the context discussed in this paper, temperature effects seem to be of less importance. 1 INTRODUCTION Formation damage is associated with flow restrictions in the region near the wellbore. This damaged zone is commonly referred to as a skin zone, i.e. a zone of reduced (positive skin) or enhanced (negative skin) permeability around the wellbore which may extend from a few inches to some feet into the formation. The radial flow pattern around a wellbore means that a certain volume of produced fluid has to pass through a smaller and smaller area as it is approaching the wellbore. Hence, the effective permeability close to the wellbore has a disproportionate effect on well productivity. A small zone of reduced permeability can reduce the productivity of the well to only a fraction of its potential value. Therefore, avoiding or removing permeability damage is of great importance to the economy of a well. Almost every field operation is a potential source of damage to the productivity of a well. Potentially damaging operations include drilling, cementing, perforating/completing, sand control, production, well stimulation and workover (Krueger 1988). Most of these operations involve some kind of fluid flow or contact between the formation and a fluid which is not a natural constituent of the formation. The main bulk of previous work is therefore related to interactions between fluids, particles and the formation. The objective of this study has been to examine other aspects of drilling-induced formation damage. Two elements of drilling-induced damage will be reported in this paper: damage caused by stress relief and damage caused by thermo- mechanical effects due to temperature variations. 2 STRESS-INDUCED EFFECTS2.1 Stresses caused by drill-out When the drill bit penetrates a formation, the stress state around the bit and the drilled veil is significantly altered from the initial in- situ state (Warren and Smith 1985). In the rock above the bottom of the hole, where local effects of the bit no longer appear, a stress alteration will be seen in the region close to the borehole. If the rock is strong enough to behave elastically, a stress concentration will occur. The removal of rock and substitution of rock with drilling fluid, reduces the support to the formation. However, if the rock is relatively weak, the rock can no longer tolerate the wellbore shear stresses of an elastic response. Given these data, and assuming a vertical well with axial symmetry, a plastic zone is generated, see Figure 1. This figure also includes an elastic stress distribution for the same case, given that the rock would be strong enough not to yield.