Wellbore Scale Research Articles

Karst control on reservoir performance of a developed carbonate geothermal reservoir in Munich, Germany

The Upper Jurassic ‘Malm’ carbonates of southern Germany are currently the most developed reservoir for geothermal energy production in Germany. Although many studies have investigated the Malm carbonate reservoir, few studies have focused on the palaeokarst system – despite the fact that the reservoir is frequently referred to as ‘Malmkarst’. Data from 25 wells in the Malm reservoir, including well logs, seismic data and hydraulic information, systematically demonstrate the presence of karstification. This is apparent in the form of large sinkholes and amplitude anomalies on the seismic scale, as well as caves observed in the image log and caliper log data. Flowmeter logs correlated with the karstified section on the image log reveal thin zones of elevated permeability, contributing most of the flow at the wellbore scale. The comparison between measurements from core data and well tests provides evidence of the reservoir's excess permeability, exhibiting values several orders of magnitude higher than those measurable in cores. The stratigraphic record suggests that karstification occurred during the Jurassic and Cretaceous, prior to the burial of the carbonates by the sediments of the alpine molasse basin.

A new wormhole mechanistic model for radial acid flow geometry using novel 3D flow correlations

In carbonate reservoirs, matrix acidizing is used to improve well performance by creating conductive channels called wormholes. Predicting wormhole propagation rate in radial acid flow geometry up to the real wellbore scale is the main problem regarding designing field operations in previous studies which are still challenging. In this study, a new mechanistic approach is presented to predict the radial flow acidizing up to near wellbore scale by considering the vital effects of porous media size and geometrical parameters of wormhole patterns.Accordingly, wormhole tip velocity and wormhole wall fluid loss rate will be introduced as the scale transferring parameters between different porous media sizes which are correlated in terms of rock diameter and wellbore height, wormhole size and density. These novel correlations are extracted from the large databank of flux distribution between rock matrix and wormhole channel obtained in 60 different 3D FEM flow simulations for various patterns of wormhole propagating and different wellbore sizes. In addition, an HPHT radial acid flooding setup is designed and constructed to perform radial acid coreflood on ultra-low permeable rocks (k«1md) for model validation. During the experiments, the breakthrough pore volume, pressure behavior and CT scan of samples are closely monitored. The results showed that due to the tight window of pore size distribution, faster breakthroughs with 1.23 and 1.45 pore volumes occurred in these tight samples compared to those reported already which are confirmed by developed model prediction. Besides, the model results showed that increasing the rock height (open-hole interval) would increase wormhole tip velocity and decrease acid breakthrough time. In addition, the higher temperature shifted the acid response curve to the right, toward higher acid breakthrough volume and higher acid concentration shifted it toward lower breakthrough volumes. The model is validated using radial acid experiments and previous radial acid models for different rock sizes with good agreement (R2 = 0.9547, MSE = 0.02161 and RMSE = 0.14701). The new radial acidizing model is capable to quickly predict wormhole propagation rate up to wellbore scale without requiring excess up-scaling data due to considering wide ranges of porous rock sizes from (25.4–152.4 cm) diameter and (5–25.4 cm) pay zone height (sufficient size for considering repetitive wormhole patterns). This technique can be utilized for tuning parameters of various radial cases to predict the acid tests results leading to reduce the number of required experiments.

Spatial complexity of burrow attributes and their impact on porosity and permeability distributions in bioturbated reservoirs

Bioturbated carbonate rocks can form high-quality aquifers and reservoirs. Although the controls on the porosity and permeability of these rocks are fairly understood at the well-bore scale, how such characteristics vary spatially across various scales of observation is still a major unsolved problem. This study integrates results of outcrop observations, imaging with scanning electron microscopy (SEM), computer tomographic (CT) scanning, petrographic analysis, and petrophysical measurements to understand how burrow intensity and burrowing style control the spatial variability of porosity and permeability of one stratum accumulated in a carbonate ramp. The CT scan data revealed two burrowing styles, pipe framework (in the upper part of the stratum, surface constrained textural heterogeneity) and bio-retexturing (in the lower part of the stratum, non-surface-constrained textural heterogeneity). The studied stratum is dominated by the micropores (cross-section>10 μm) of the host rock matrix (HRM), which comprise >50 % of the total porosity within the stratum. Porosity in the stratum does not vary substantially in vertical or lateral trends. In contrast, and perhaps most importantly, permeability does vary vertically and laterally depending on the scale of measurement, burrow percentage, and burrowing style. These results suggested that the storage capacity of the studied stratum is independent of bioturbation, whereas the flow capacity is strongly dependent on bioturbation. There is a substantial vertical change in permeability in the stratum in comparison to only small changes in the lateral direction across the layer of interest. The data also suggested that the subtle lateral change in permeability is controlled by bio-retexturing, which resulted in the homogenization of grain-dominated and mud-dominated sediments by bioturbation. Such a process can be destructive for the permeability compared to the pipe-connected burrowing style. We clearly show that the ichnologically-controlled porosity and permeability trends of the studied stratum are relevant at the field scale. Understanding such trends in the context of paleoenvironmental conditions provides insight into the fluid flow quality of bioturbated carbonates, which constitute a large proportion of water aquifers and hydrocarbon reservoirs globally.

Numerical simulation inversion of creep laws of composite salt layers based on reaming while drilling

The composite salt layer of the Kuqa piedmont zone in the Tarim Basin is characterized by deep burial, complex tectonic stress, and interbedding between salt rocks and mudstone. Drilling such salt layers is associated with frequent salt rock creep and inter-salt rock lost circulation, which results in high challenges for safe drilling. Especially, the drilling and completion processes of the salt-gypsum layers of one typical group are found with frequent downhole accidents and complex issues, such as hole shrinkage, sticking, well kick, and lost circulation, which leads to high difficulties in delivering desirable cementing quality and severely hinders the subsequent safe rapid drilling. Reaming while drilling can effectively enlarge the wellbore diameter, provide extra tolerance for creep shrinkage of salt layers, and ultimately help to shorten drilling time, reduce accidents and complex issues, and improve the lifecycle of wells. In this research, a numerical simulation method was developed to invert the creep laws of composite salt layers, based on reaming while drilling. It is generally believed that the dislocation creep mechanism is dominant in coarse-grained salt rocks, while the pressure solution creep mechanism is dominant in fine-grained salt rocks. Here a well in the Dabei area was taken as an example and the numerical simulation of hole shrinkage at the wellbore scale was performed, based on the actual data before and after reaming and also the theoretical analysis of the two salt rock creep mechanisms and corresponding laws. Furthermore, the inversion results were validated using field data. This research discussed the selection of creep parameters and their variation, in cases of the dominance of the dislocation creep and pressure solution creep mechanisms. This presented method can accurately predict the creep behavior of salt layers and can be used as an effective supplement tool for other test methods like laboratory experiments.

The fluid flow modeling procedure including a critically stressed fracture analysis of coalbed methane reservoir: a case study of Upper Silesian Coal Basin, Poland

The geomechanical modeling turned out to be an essential component of the hydrocarbon exploration assisting reduction of risk of drilling issues and optimization of hydraulic fracturing treatment. This study provides a workflow of critically stressed fracture (CSF) analysis dedicated for coal layers. The main focus of the paper is applying the 1D mechanical models and following modelling of hydraulic fracturing treatment to describe the fracture behavior under the impact of the stresses at the wellbore scale. Another objective of the presented study is demonstration of benefits of 1D and 3D CSF analysis to understand fracture contribution to gained volume of hydrocarbon after fracturing of coal seam. Interpretation of fracture orientation and their behavior is vital to effective development of coal bed methane (CBM) resources as the CSF can be responsible for considerable part of CBM production. Natural fractures and faults contribute to fluid flow through rock. It is often noted that natural fractures may not be critically stressed at ambient stress state. However, during stimulation, the optimally oriented natural fracture sets have the inclination to become critically stressed. Hence, understanding of the recent stress state and fracture orientations is significant for well planning and fracturing design. The outcome of this study are comprehensive 1D mechanical Earth models (MEMs) for analyzed wells and explanation of behavior of identified CSF under variable stress state as well as understanding of the connectivity of natural fractures within zone subjected to fracturing treatment.

Experimental and Statistical Study on Wellbore Scaling Mechanisms and Characteristics for Huanjiang Oilfield

Wellbore scaling is a complex and one of the common problems encountered during the depletion of an oilfield. Many studies have been conducted on general scale mechanisms, scale predictions, and removal measurements. However, the detailed study of the scaling characteristics and mechanisms in Huanjiang oilfield is limited. The objective of this work is to investigate the scaling mechanisms and characteristics to provide guidance for scale inhibitor selection, synthesis, and testing in the Huanjiang oilfield. Ion chromatography (IC) was used to test the composition of 100 water samples, and energy dispersive spectroscopy (EDS), scanning electron microscope (SEM), and X-ray diffraction (XRD) were utilized to analyze the composition of 120 wellbore scale samples that were collected from the Huanjiang oilfield. The results show that the water types of formation and groundwater are CaCl2 and Na2SO4, respectively. The oil wells produced from Chang 4 + 5 , Chang 6, and Chang 8 reservoir layers in the development of Yanchang group are mainly calcium-based scale (CaCO3 and CaSO4), supplemented by wax deposition scale, corrosion scale, and NaCl and KCl crystal scale. In contrast, the oil wells in Yan’an group (Yan 6, Yan 7, Yan 8, Yan 9, and Yan 10 reservoir layers) are mainly wax deposition scale and corrosion scale.

Awi A-4 Comprehensive Well Evaluation for Successful Well Intervention Program

AWI A-4 well has the highest Non-Condensable Gas (NCG) content among other production wells in the Salak field with NCG content 10%-wt. NCG interference study indicated that AWI A-4 has the most substantial connection/interference to several surrounding high NCG wells. AWI A-4 encountered wellbore obstruction (scaling) in 2012, which increased the NCG content of surrounding wells and power plant Unit-4, causing generation loss. Another impact is steam supply reduction by 71.8 kg/s because of maintaining Unit-4 NCG content below its maximum Gas Removal System (GRS) capacity by 2%-wt. Wellbore scale clean out was conducted in 2015 but failed and even plugged the wellbore. A comprehensive evaluation of well AWI A-4 wellbore condition and well characterization was conducted involving a multidisciplinary team (Drilling, Reservoir, Production, Geochemistry) in order to obtain a better understanding of the main cause of well AWI A-4 wellbore plug then develop the proper method to clean the wellbore plug and improve wellbore accessibility. After evaluating well AWI A-4 wellbore condition comprehensively, a new scale clean out program was developed using rotojet Coiled Tubing Unit (CTU) in 2017 which was finally able to improve wellbore accessibility well AWI A-4 including NCG content reduction of surrounding high NCG wells and power plant Unit-4. This successful wellbore accessibility improvement has a positive impact on additional/incremental steam supply by 84.4 kg/s, including other steam supply projects delay and cancellation, so that reduce the company’s operational cost.

Karst feature in Mishrif Reservoir and effect on drilling and production in Zubair oil field, Southern Iraq

Karst features in the upper part of Mishrif carbonate reservoir can commonly create substantial vugs, pores and fissures and, thus, increasing the porosity and enhancing reservoir connectivity and permeability, this features were formed normally as a result of the carbonate rocks dissolution under the action of meteoric waters during very long periods of emersion spanning from Late Cenomanian to Turonian (about 4.5 Million years). This study deals with the presence of the karst features in Zubair oil field, southern Iraq, where Karst features were observed in the center and northern parts of the field close to the top of Mishrif Formation in most of the cored wells. Characterization of that feature can be achieved from static data at wellbore scale from core, and logs (conventional and non-conventional), and dynamic data such as mud losses, well tests combined with production logs (PLT) in addition to Seismic data. Beside the positive and economic effect of Karst, there is negative effect which includes causing mud losses during drilling in Mishrif Formation because of low reservoir pore pressure, Therefore, acid soluble cement plugs were used to heal that losses to continue drilling.

Facile one-pot synthesis of metal-phosphonate colloidal scale inhibitor: Synthesis and laboratory evaluation

Mineral scale deposition is a serious flow assurance concern threatening the safety and integrity of oilfield operations. Subsurface and wellbore scale control is commonly managed by scale squeeze treatment. Compared to the conventional chemical inhibitor pill applied in a scale squeeze treatment, colloidal scale inhibitor materials are capable of enhancing inhibitor transportability in formation medium and extending squeeze lifetime. A number of functional scale inhibitor colloidal materials have been synthesized in the previous studies including the crystalline low solubility materials. However, these reported synthesis routes are complicated to follow, involving extensive experimental setup. In this study, a one-pot synthesis route has been presented to prepare metal-phosphonate colloidal inhibitor (MPCI) material in a facile and economical manner. This method is based upon a citrate-assisted approach where a low solubility MPCI material with 40 nm particle size can be produced. Laboratory transport experiment suggests that calcium-based MPCI can be transportable through sand medium at representative oilfield conditions with 100% breakthrough realized within 2.5 pore volumes in sand-packed column. Laboratory squeeze simulation tests indicate that this material is able to return inhibitor with a stable return concentration for an extended squeeze lifetime. The calculated normalized squeeze lifetime of calcium-based MPCI is as high as 1100 m3 kg−1 in sand medium. Magnesium and Zirconium based MPCI can increase the stabilized inhibitor return concentration up to 3 mg L−1. This study expands our understanding of the colloidal inhibitor materials and promotes the potential field application of such materials for oilfield scale squeeze treatment.

The Erskine Field, Block 23/26b, UK North Sea

Abstract The Erskine high-pressure–high-temperature gas condensate field was the first such field developed in the UK Continental Shelf. Since production started in 1997, the field has produced over 350 bcf of gas and 70 MMbbl of condensate. The reservoir pressure has depleted from an initial pressure of 960 bar (13 920 psi) down to 140–400 bar (2030–5800 psi), resulting in some compaction and sand production in some of the wells. Free water production has led to the formation of wellbore scale, which has required interventions to remove. The reservoirs are sandstones of the Jurassic Puffin, Pentland and Heather formations. Estimates of hydrocarbons in place made using production and pressure data compare favourably with the initial estimates made during field development planning, although the Pentland Formation volume is some 20% below the sanction estimate. Several major field outages have occurred, such as a condensate fire in 2010 and a blockage of the multiphase export pipeline in 2007. In addition, the field has experienced flow assurance problems related to scale and wax deposition. A new pipeline section was installed in 2018 to bypass a full pipeline blockage which occurred due to wax deposition.

Sweet spot identification through seismic inversion and multiattribute transform: A case study of the Niobrara and Codell unconventionals

The Niobrara and Codell unconventional tight reservoir play at the Wattenberg field, Colorado, has potentially two billion barrels of oil equivalent, requiring hundreds of wells to access this resource. Due to the formations’ high heterogeneity and variable thicknesses, we model the facies at the well-bore scale and upscale it to the seismic scale to guide the development strategy and evaluate future exploration targets. A facies classification from well data supervises the prestack seismic inversion and multiattribute transformation workflows to build a 3D facies model. The 3D facies model captures the reservoir heterogeneity throughout the study area and suggests the location of sweet spots for future hydraulic fracturing and refracturing. The term “sweet spot” refers to the parts of the rock formation that potentially have the highest hydrocarbon production. The significance of sweet spot identification includes improved recovery from the Niobrara, Codell, and potential deeper intervals for future exploration of drilling targets. Furthermore, sweet spot information also assists in keeping the well in formation, which is difficult to do without the seismic data. Keeping the well in formation is key for the efficiency of hydraulic fracturing operations and improved production.

Pseudo-Elastic Response of Gas Bearing Clastic Formations: An Italian Case Study

The research presented in this paper focuses on the analysis of land movements induced by underground gas storage operations in a depleted reservoir in Northern Italy with the aim of increasing the understanding of the deformation response of deep formations via a real case study. The a priori knowledge of the pseudo-elastic parameters showed a substantial discrepancy between static values from triaxial lab tests and dynamic values obtained via the interpretation of sonic data at wellbore scale. The discrepancy is not surprising for the formations under investigation: a thousand meters of a silty to shaly sequence intercalated with arenaceous banks above a reservoir formation, which is basically made up of sandstone intercalated with shale intervals and conglomerates. Information collected for over more than ten years of seasonal production/injection cycles (i.e., time and space evolution of the reservoir fluid pressure and of the induced land surface movements) was then combined in a 3D numerical geomechanical model to constrain and update the a priori knowledge on the pseudo elastic model parameters via a back analysis approach. The obtained calibrated model will then be used for reliable prediction of system safety analyses, for example in terms of induced ground movements.

Promoting wellbore stability in active shale formations by water-based muds: A case study in Pabdeh shale, Southwestern Iran

Minimizing water invasion into shales is a critical property for many water-based muds. By improving drilling fluids rheology in HPHT conditions, it is possible to minimize water invasion and maintain true overbalance pressure conditions at near wellbore scale which endorses wellbore stability. In order to propose an inhibitive mud formulation for drilling troublesome swelling Pabdeh formation frequently encountered in southern to southwestern regions of Iran, a comprehensive experimental approach was adopted. After performing rheology and thermal stability tests for 81 different formulations of drilling fluids, 5 high performance salt/polymer solution muds were chosen. They showed good rheology properties and all of them were thermally stable. In order to find the best formulation which accomplishes all requirements pertaining shale stability and wellbore integrity, some complementary analyses were performed. Using a roller oven simulating down hole temperature conditions, physical integrities of shale samples immersed and rolled in these 5 mud formulations were investigated. Pore pressure transmission tests were also carried out using a membrane efficiency screening equipment to evaluate membrane efficiency of the Pabdeh shale and also inhibitive performances of 5 designed mud formulations. Accordingly, pore pressure evolution in shale samples in contact with designed muds were obtained by direct measurements, which resembles the near wellbore pore pressure alterations. According to the obtained results, Pabdeh shale shows negligible membrane efficiency of about 4%. Although all mud formulations show high surface coating capabilities resulting in almost high shale recovery after exposure, pore pressure transmission tests revealed different inhibitive performances. Among them, a combination of polymers and sodium silicate shows promising mud formulation that hinders filtrate invasion into shale samples by either physical or chemical plugging of the shale pore throats. Regarding both environmental and economical aspects of drilling operations, derived mud formulations can also be advantageous for drilling safe and stable wells in Pabdeh formation.

Proppant Distribution Among Multiple Perforation Clusters in Plug-and-Perforate Stages

Summary Plug-and-perforate (Plug-and-Perf) fracturing stages with multiple perforation clusters have become common practice in the industry. However, it is usually unclear whether the fluid and proppant are distributed evenly among all clusters. In this study, we present a method for computing the proppant distribution into each cluster in a fracturing stage. By integrating proppant transport into a multicluster hydraulic-fracturing model and implementing a simple screenout criterion, we show that the proppant distribution in a fracturing stage can be very uneven, with a strong bias toward the heel-side clusters even when the initial fluid distribution is uniform among all clusters. In this work, we define the efficiency of proppant transport into a perforation by the proppant-transport efficiency (PTE), which is defined as the mass fraction of proppant transported through a perforation relative to the total mass of proppant approaching the perforation. The dynamic proppant distribution in a fracturing stage is modeled with the PTE concept in three steps. First, a series of coupled computational-fluid-dynamics/discrete-element-method (CFD/DEM) simulations were performed to obtain PTE under controlled flow conditions. Then, the CFD/DEM simulation results were statistically analyzed to generate a PTE correlation as a function of wellbore, perforation, fluid, and proppant properties. Finally, the PTE correlation was incorporated into a multicluster hydraulic-fracturing model to compute the dynamic distribution of fluid and proppant among multiple clusters in a fracturing stage. Results from this work show that proppant concentration in the toe-side clusters can be several times higher than the injected concentration. This occurs because the high wellbore flow rate near the heel-side clusters provides proppant particles a large inertia sufficient to prevent them from turning into the perforations. Proppant concentration in the wellbore is thus increased as the slurry flows toward the toe side and the fluid preferentially leaks off from the heel-side perforations. The highly concentrated slurry increases the screenout risk of the toe-side clusters. Our modeling results show that if toe-side clusters screen out at early time in the proppant stage, fluid and proppant are redistributed to the heel-side clusters. In such a case, cumulative fluid and proppant distributions will be heel-biased. Simulation results are compared with field observations and are shown to be consistent with distributed-temperature-sensing (DTS) and distributed-acoustic-sensing (DAS) observations on proppant distribution made in three different studies. The method presented in this work provides a way to quantify proppant transport at a wellbore scale. It shows that the uneven proppant distribution among perforation clusters is a function of fluid, perforation, and proppant properties. An estimate of proppant placement in different perforation clusters can be computed for any pumping schedule and wellbore/perforation geometry with this method. This can be used to optimize perforation clusters that will result in a more-even distribution of proppant in each cluster.

Estimation of earth stresses and fracture properties using numerical method and soft computing

Recently, artificial neural networks ANNs have been introduced to solve petroleum geomechanics characterisation problems dealing with the inherent nonlinear relationship in well log data. This paper presents a computational intelligence algorithm of artificial neural network ANN and genetic algorithm GA, which is studied and applied in petroleum geomechanics to estimate the information of earth stresses and fracture properties based on wellbore displacement information when drilling well. In this computational intelligence algorithm, an ANN is used to represent the nonlinear relationship between the petroleum geomechanics parameters and the wellbore deformation. GA is used to identify the set of unknown earth stresses and natural fracture properties at wellbore scale in a large space based on the objective function. Our experiments illustrate that the proposed computational intelligence method is able to generate reliable results.

Assessment of the structural representativeness of sample data sets for the mechanical characterization of deep formations

Accurate characterization of the mechanical behavior of geomaterials at depth is a fundamental need for geologic and engineering purposes. Laboratory tests on samples from well cores provide the material characterization in terms of mechanical response and other relevant properties. Representativeness of a sample data set with respect to the in situ conditions at depth is a key issue, which needs to be addressed to extrapolate the laboratory response to the whole rock mass. We have developed a procedure aimed at quantitatively evaluating the representativeness of laboratory samples. The methodology is based on joint processing of laboratory ultrasonic tests and wellbore sonic logs. A structural index is used to quantify the difference between the average structure of the laboratory sample and the structure of the formation at the wellbore scale. This index could be used to identify different causes of discrepancies between the behavior of the cored samples and the behavior of the rock formation as documented by well logs. Then, it could also be used to integrate laboratory data for the construction of a reliable geomechanical model with reference to the real in situ state. The methodology was applied to three different experimental data sets, showing the effectiveness of the method.

Determination of horizontal in-situ stresses and natural fracture properties from wellbore deformation

Accurate and low-cost information on in-situ stresses and fracture properties is critical in reducing well costs and increasing well recoveries. In this paper, a hybrid model based on the displacement back analysis is proposed for determining the in-situ stress magnitudes and fracture properties at the wellbore scale using wellbore displacements. The new methodology is an integration of artificial neural network (ANN), genetic algorithm (GA), and numerical analysis. An ANN is used to map the non-linear relationship between the maximum and minimum horizontal in-situ stresses (σH, σh) and natural fracture properties (e.g., joint angle, θ, aperture, a1 and a2, and spacing, s) and the wellbore displacements. A forward modelling (UDEC) is used to compute wellbore displacements as a function of horizontal in-situ stresses and natural fracture properties, and to create the necessary training and testing samples for ANN. The set of unknown horizontal in-situ stresses and natural fracture properties at wellbore scale are searched in a global space using GA based on the objective function. Results of the numerical experiment show that the hybrid ANN-GA model based on the displacement back analysis can effectively recognise the horizontal in-situ stresses and natural fracture properties from wellbore deformation during drilling.

CO2Injectivity in Geological Storages: an Overview of Program and Results of the GeoCarbone-Injectivity Project

The objective of the GeoCarbone-Injectivity project was to develop a methodology to study the complex phenomena involved in the near wellbore region during CO2 injection. This paper presents an overview of the program and results of the project, and some further necessary developments. The proposed methodology is based on experiments and simulations at the core scale, in order to understand (physical modelling and definition of constitutive laws) and quantify (calibration of simulation tools) the mechanisms involved in injectivity variations: fluid/rock interactions, transport mechanisms, geomechanical effects. These mechanisms and the associated parameters have then to be integrated in the models at the wellbore scale. The methodology has been applied for the study of a potential injection of CO2 in the Dogger geological formation of the Paris Basin, in collaboration with the other ANR GeoCarbone projects.

Near-Wellbore Modeling: Sand-Production Issues

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 109894, "Near-Wellbore Modeling: Sand-Production Issues," by Guillaume Servant, IFP; Philippe Marchina, SPE, Total; and Jean- Francois Nauroy, IFP, prepared for the 2007 SPE Annual Technical Conference and Exhibition, Anaheim, California, 11-14 November 2007. The paper has not been peer reviewed. Sand production in an oil or gas well can cause operational difficulties, but it contributes to production enhancement by improving the well inflow performance. To assess the relative magnitude of those effects and to optimize the well completion and operation, a quantitative forecast of the expected amount and rate of sand production must be made. This forecast requires a correct description of all the mechanisms involved in sand production, sand transport in particular. The proposed numerical method considers that the geomechanical problem (rock failure) interplays with the transport of sand. Equilibrium equations that control rock failure (solid mechanics) and sand transport (fluid mechanics) are solved simultaneously by an iterative coupled scheme at the wellbore scale. Introduction Sand production causes production problems and can generate safety and environmental hazards. However, it can increase the inflow performance of the well. Therefore, the option of installing downhole sand-control equipment may not always be the best economic solution for the project. Heavy-oil reservoirs can benefit from allowing sand to be produced with the oil. This technique, known as cold-heavy-oil production with sand (CHOPS), allows higher production rates than conventional techniques. Again, the productivity and ultimate delivery of the well will depend on the amount of sand produced. Therefore, the ability to anticipate the sand-production mechanisms in terms of sand rate and volumes, and anticipate sand-producing patterns in the reservoir, is required for optimized development of such fields. Two mechanisms contribute to sand production: rock failure (through which freed sand grains are generated) and transport of those free grains by the effluents into the wellbore and up to surface. Most current sand-production-risk models concentrate on the rock-failure analysis and, as such, can determine only the conditions for the onset of sand production. In the proposed model, the rock-mechanical aspects are coupled to the sand-transport problem. Therefore, interaction between the solid matrix and the slurry flow can be analyzed and translated into quantitative sand production. Paralleling development of this numerical model, a series of sand-production experiments was carried out in a purpose-built laboratory apparatus with the objectives of understanding the sand-production processes in uncemented reservoirs better and providing high-quality data sets for calibrating the model.

Experimental investigation of CO 2–brine–rock interactions at elevated temperature and pressure: Implications for CO 2 sequestration in deep-saline aquifers

Deep-saline aquifers are potential repositories for excess CO 2, currently being emitted to the atmosphere from anthropogenic activities, but the reactivity of supercritical CO 2 with host aquifer fluids and formation minerals needs to be understood. Experiments reacting supercritical CO 2 with natural and synthetic brines in the presence and absence of limestone and plagioclase-rich arkosic sandstone showed that the reaction of CO 2-saturated brine with limestone results in compositional, mineralogical, and porosity changes in the aquifer fluid and rock that are dependent on initial brine composition, especially dissolved calcium and sulfate. Experiments reacting CO 2-saturated, low-sulfate brine with limestone dissolved 10% of the original calcite and increased rock porosity by 2.6%. Experiments reacting high-sulfate brine with limestone, both in the presence and absence of supercritical CO 2, were characterized by the precipitation of anhydrite, dolomitization of the limestone, and a final decrease in porosity of 4.5%. However, based on favorable initial porosity changes of about 15% due to the dissolution of calcite, the combination of CO 2 co-injection with other mitigation strategies might help alleviate some of the well-bore scale and formation-plugging problems near the injection zone of a brine disposal well in Paradox Valley, Colorado, as well as provide a repository for CO 2. Experiments showed that the solubility of CO 2 is enhanced in brine in the presence of limestone by 9% at 25 °C and 6% at 120 °C and 200 bar relative to the brine itself. The solubility of CO 2 is enhanced also in brine in the presence of arkosic sandstone by 5% at 120 °C and 300 bar. The storage of CO 2 in limestone aquifers is limited to only ionic and hydraulic trapping. However, brine reacted with supercritical CO 2 and arkose yielded fixation and sequestration of CO 2 in carbonate mineral phases. Brine desiccation was observed in all experiments containing a discrete CO 2 phase, promoting porosity-reducing precipitation reactions in aquifers near saturation with mineral phases.