bluuebunny/crossref_metadata_2025_split huggingface dataset:
Waterflooding Under Dynamic Induced Fractures: Reservoir Management and Optimization of Fractured Waterfloods
Authors: van den Hoek P. J. , Al-Masfry R. , Zwarts D. , Jansen J. D. , Hustedt B. , van Schijndel L. 
Published: April 2008

Abstract
It is well established within the Industry that water injection mostly takes place under induced fracturing conditions. Particularly in low-mobility reservoirs, large fractures may be induced during the field life.
This paper presents a new modeling strategy that combines fluid-flow and fracture-growth (fully coupled) within the framework of an existing ‘standard’ reservoir simulator.
We demonstrate the coupled simulator by applications to five-spot pattern flood models, addressing various aspects that often play an important role in waterfloods: shortcut of injector and producer, fracture containment, reservoir sweep. We also demonstrate that induced fracture dimensions can be very sensitive to typical reservoir engineering parameters, such as fluid mobility, mobility ratio, 3D saturation distribution (in particular, shockfront position), positions of wells (producers, injectors), and geological details (e.g. flow baffles).
The results presented in this paper are expected to also apply to (part of) EOR operations (e.g. polymer flooding).
Labyrinth Packer Lowers the Costs for Steam Injection Wells: Theoretical and Experimental Results
Authors: Teodoriu C. , Falcone G. 
Published: April 2008

Abstract
This paper describes a low-cost completion technique that uses conventional tubing and replaces the expensive thermal packer with a new low-cost design. The new design allows free tubing expansion and protects casing through continuous gas circulation in the annulus. It also makes possible simultaneous injection of combustion gases from steam generators, when conventional systems are used, or small amounts of nitrogen, when the generators are not available.
Comparison Study of Capillary Pressure Curves Obtained Using Traditional Centrifuge and Magnetic Resonance Imaging Techniques
Authors: Green D. P. , Gardner J. , Balcom B. J. , McAloon M. J. , de J. Cano-Barrita P. F. 
Published: April 2008

Abstract
The current study is a comparison trial of a new Magnetic Resonance Imaging (MRI) method for acquiring capillary pressure versus traditional techniques. This study is meant to evaluate the methodology and workflow by performing measurements at the University of New Brunswick, Canada and on-site with CoreLab in Houston, TX, USA. This study focuses on gas-brine primary drainage capillary pressure systems.
Traditional centrifuge capillary pressure measurements require the fluid(s) to reach equilibrium at many different speeds. This is very time consuming as each equilibrium step can take a couple of days. In addition, the inlet saturation must be computed using an approximate solution that is known to cause errors. Porous plate capillary pressure measurements are considered the most accurate but acquiring the complete curve can take months.
The new method (GIT-CAP) centrifuges the core plugs then directly measures the water saturation distribution inside the core plug using MRI. The measured water saturation together with the known centrifugal force directly leads to a capillary pressure curve.
Conventional medical based MRI methods have difficulty in relating the detected signal intensity to water or oil saturation. This is because the MRI image intensity depends on the environment of hydrogen atoms which changes based on saturation level. In this work, we use a new MRI method, one dimensional centric scan Single-point Ramped Imaging with T1 Enhancement (SPRITE), in which the detected signal is directly proportional to the amount of water or oil present.
The new technique measures the capillary pressure curve more quickly and accurately. It is also three to five times faster since only two to three centrifuge speeds are required (versus seven to ten). In some rock types, this reduces the measurement duration from many weeks to days. The new technique is also potentially more accurate as it directly measures the water saturation in the rock instead of relying on a calculation using a measurement of the expelled water. The current study focuses on gas-water systems comparing traditional capillary pressure measurements with the new MRI-based method.
Effect of Miscible and Immiscible CO2 Flooding on Gravity Drainage: Experimental and Simulation Results
Authors: Asghari K. , Torabi F. 
Published: April 2008

AbstractImplantation of EOR processes in naturally fractured reservoirs is a challenging task due to preence of extereme heterogeneity. Among potential EOR techniques for implementing in these environments application of CO2 for displacement purposes and/or pressure maintenance might be a viable option. This paper presents the results experimental and simulation studies of the effect of injecting CO2 into fractured media and its influence on oil recovery. Both miscible (i.e. high pressure) and immiscible (i.e. low pressure) schemes for CO2 are investigated in a core of 100 md permeability. The results obtained from these experiments are used to compare the effect of miscible versus immiscible conditions. For these experiments a special stainless steel holder was designed that allows an open space around a core of 30 cm long and 5 cm in diameter, simulating a matrix with surrounding fractures. Carbon dioxide and normal decane were used as solvent and oil, respectively. The core weas saturated with oil with and without presence of residual water saturation. While all experiments were conducted at constant temperature of 35 °C, six series of experiments were carried out at 250, 500, 750, 1000, 1250, and 1500 psi. A high pressure calibrated glass-gauge was connected to the bottom of the fractured media model allowing the produced oil be collected and measured continuously under the pressure and temperature conditions of the experiments. Analyzing the results show that injecting CO2 at higher pressures improves the recovery factor of gravity drainage mechanism in fractured media, significantly.
A Methodology to Design Exploitation Plans through the Application of Thermal Process, Orocual Field, Venezuela
Authors: Anaya I. , Hernandez M. M. , Luces A. , Serna A. J. 
Published: April 2008

Abstract
Orocual is the most complex Field in Monagas, eastern Venezuela. Due to its complexity it has been divided vertically into two zones: shallow (heavy oil) and deep (light oil and condensate). The OOIP in shallow reservoirs is reported as 3500 MMSTB. The reservoir pressure is close to original conditions due to low historical production. Therefore, the current oil recovery factor is less than 1%. To date, cyclic steam injection pilot was applied to 5 wells and the initial oil rate showed to be as high as five times the cold production in vertical wells and six times the cold production for horizontal wells. According to the results of the pilot test, the future development of shallow Orocual will be mainly based on the application of thermal processes. This paper shows a methodology to design an exploitation plan through the application of thermal process. The first step involves analyzing the reservoir by sectors in order to determine which thermal process is appropriate to the reservoir; the second step is building sector models to simulate each process and optimize operational parameters. For the first time cyclic steam injection, steamflooding and steam assisted gravity drainage were simultaneously simulated in the same model. According to this study it is possible to maximize the production of these reservoirs, accelerate the exploitation of its reserves and optimize operational parameters in thermal recovery, as well as determine critical factors for each process. This study shows that numerical simulation of complex process can be efficiently carried out in FullField scale.
Hysteresis and Field-Scale Optimization of WAG Injection for Coupled CO2-EOR and Sequestration
Authors: Ghomian Yousef , Pope Gary A. , Sepehrnoori Kamy 
Published: April 2008

Abstract
The effect of relative permeability hysteresis on both CO2 storage and oil recovery has been studied using a compositional simulator. The effects of process parameters such as water-alternating-gas (WAG) ratio and CO2 slug size, and reservoir heterogeneity characteristics such as Dykstra-Parson coefficient and correlation lengths on CO2 storage and tertiary oil recovery were simulated using hysteresis based upon existing correlations. Three different relative permeability and capillary pressure models for three different rock types in the reservoir were carefully constructed. Reservoir fluid PVT data were used to develop the Equation-of-State (EOS) model. A grid refinement study was performed to evaluate the numerical convergence behavior of the simulation model with the hysteresis option included. In the refined cases, it was necessary to apply a higher-order approximation scheme to reduce the numerical dispersion of the simulations. In addition, due to the application of very small gridblock sizes, physical dispersion was also taken into account. Experimental design and statistical analysis were used to understand the most influential factors on oil recovery, project net cash flow, and CO2 storage. Optimization was carried out and response surfaces were constructed to quantify the effect of each parameter.
Injectivity Changes and CO2 Retention for EOR and Sequestration Projects
Authors: Grigg Reid B. , Svec Robert K. 
Published: April 2008

Abstract
The apparent consequences of increased greenhouse gas emissions is encouraging increased carbon dioxide (CO2) injection into oil reservoirs for enhanced oil recovery (EOR) and we are seeing the start of carbon storage in other geological formations, especially deep saline aquifers (Rogers and Grigg, 2001). The development of CO2 plumes and their subsequent transport and dissolution into formation brine are essential mechanisms in most storage scenarios. The study of these will aid in understanding long-term injectivity reduction in EOR WAG (water alternating with gas injection) projects. This paper describes laboratory tests on sandstone and carbonate core samples. Two types of displacement tests were performed at reservoir conditions: gas injection into brine saturated core until residual brine saturation is reached with respect to gas, then this is followed by brine injection into this core that had previously been flooded to a residual gas with respect to brine. In some cases the brine was injected until all the residual gas was removed by dissolution. The level of CO2 saturation in the injected brine at reservoir pressure and temperature was varied from zero to over 90% saturation. This variation in CO2 saturation in the injected brine determined the reduction rate of the CO2 saturation or plume after residual gas saturation was reached. This information can be used in CO2-EOR WAG projects and for carbon storage into geological formations.
The injection of CO2 into brine-saturated sandstone and carbonate core results in brine saturation reduction to from 62 to 82% brine in the tests presented in this paper. In each test, over 90% of the reduction occurred with less than 0.5 PV of CO2 injected, with very little additional brine production after 0.5 PV of CO2 injected. During brine injection, CO2 production was equivalent to the rate expected from brine saturated with CO2 at reservoir conditions, except for the first ~0.1 PV of the Queen Sandstone CO2 production. This indicates that in each core at high end-point brine saturation at the tested flow rate (~2 m/day) the CO2 plume was reduced through by solution, not displacement. With increasing CO2 saturation in the injected brine, the brine volume required to remove (dissolve) the CO2 plume increased proportionally. Results will be used to aid in predicting injectivity in CO2-EOR-WAG operations and CO2 plume migration and CO2 dissolution in EOR and sequestration projects.
Production Enhancement in Gas-Condensate Reservoirs by Altering Wettability to Gas Wetness: Field Application
Authors: Liu Yijiang , Zheng Hongwen , Huang Guixiong , Li Ganqin , Li Kewen 
Published: April 2008

Abstract
Liquid condensation in the rock near wellbore may kill gas production in gas-condensate reservoirs when pressure drops lower than the dew point. It has been proved both theoretically and experimentally that gas production in gas-condensate reservoirs could be improved by altering wettability of rock near wellbore from liquid wetness to gas wetness. However, to our best knowledge, few field applications have been reported. In this study, a pilot test was designed based on experimental results measured in the rock sampled from the target gas-condensate reservoir. The gas-condensate field, located in central China, was a high temperature and low permeability reservoir with a permeability of less than 0.1 md. About 30,000 litters of chemical solution were injected into a well in the gas-condensate field. The test results showed that the gas production of the well was increased significantly.
Developing a Chemical EOR Pilot Strategy for a Complex, Low Permeability Water Flood
Authors: Fletcher A. J. P. , Morrison G. R. 
Published: April 2008

Abstract
A screening study and subsequent chemical EOR application pilot strategy for a complex, low-permeability waterflood is presented. Our focus has been on developing appropriate field application options allowing flexibility of operation against a background of reservoir complexity and uncertainty.
Australia's Barrow Island Windalia reservoir, the nation's largest onshore waterflood, was developed in the late 1960's. Cumulative oil production to date is approximately 288 MMSTBO. Planning a chemical EOR scheme needs to address the following reservoir and production characteristics:
Highly heterogeneous, very fine grained, bioturbated argillaceous sandstone, high in glauconite; High porosity (0.28) but low permeability (5 mD with 20 mD+ streaks); Production and injection necessarily stimulated by induced fractures Highly saline and hard brine; Large waterflood pattern volumes (10 MMbbl at 20 acre well spacing).
Despite 40 years of production involving water flooding, well-work, and changes in operating philosophy, the nature of the reservoir presents significant uncertainties. These uncertainties flow-on to difficulty in constructing predictive reservoir models.
Initial screening recommended that polymers be considered for sweep improvement and conformance control although reservoir complexity presented a challenge. Subsequent laboratory work focused on issues of polymer injectivity, rheology, and retention, in parallel with an assessment of how SCAL properties are measured in the laboratory and related to water flood performance. Dynamic modelling studies have assessed field response and economics for a range of chemical EOR pilot designs.
We have focused on developing options for field application of polymers, as opposed to extensive stand-alone laboratory and dynamic modelling studies, in order to address reservoir uncertainties and forecast production response. Results from the proposed polymer pilot flood will allow assessment of further chemical EOR applications and potential field-wide scale up.
We propose a mechanism, termed in-depth flow diversion (IFD), which may operate in low permeability, fractured injector water flood. This would allow polymer EOR to operate in lower permeability water flood than currently envisaged.
Efficient Ensemble-Based Closed-Loop Production Optimization
Authors: Chen Yan , Oliver Dean S. , Zhang Dongxiao 
Published: April 2008

Abstract
With the advances in smart well technology, substantially higher oil recovery can be achieved by intelligently managing the operations in a closed-loop optimization framework. The closed-loop optimization consists of two parts: geological model updating and production optimization. Both of these parts require gradient information to minimize or maximize an objective function: squared data mismatch or the net present value (or other quantities depending on financial goals), respectively. Alternatively, an ensemble-based method can acquire the gradient information through the correlations provided by the ensemble. Computation of the optimal controls in this way is nearly independent of the number of control variables, reservoir simulator and simulation solver. In this paper, we propose an ensemble-based closed-loop optimization method that combines a novel ensemble-based optimization scheme (EnOpt) with the ensemble Kalman filter (EnKF). The EnKF has recently been found suitable for sequential data assimilation in large-scale nonlinear dynamics. It adjusts reservoir model variables to honor observations and propagates uncertainty in time. The EnOpt optimizes the expectation of the net present value based on the updated reservoir models. The proposed method is fairly robust, completely adjoint-free and can be readily used with any reservoir simulator. The ensemble-based closed-loop optimization method is illustrated with a waterflood example subject to uncertain reservoir description. Results are compared with other possible reservoir operation scenarios, such as, wells with no controls, reactive control, and optimization with known geology. The comparison shows that the ensemble-based closed-loop optimization is able to history match the main geological features and increase the net present value to a level comparable with the hypothetical case of optimizing based on known geology.
Using a Discritized Well Model to Simulate Production Behavior in Horizontal or Multi-Lateral Wells
Authors: Wang Yuandong , Shan Dan , Heim Robin N. 
Published: April 2008

Abstract
Horizontal and multi-lateral wells have become increasingly important and represent a growing percentage of production wells. They are used to maximize the well to reservoir contact and improve oil recovery in a cost efficient manner. This is especially true for offshore fields where these wells are used to drain large areas with limited platform capacities. Commonly, a horizontal well trajectory undergoes undulations that may result in special wellbore flow dynamics. In addition, technologies such as intelligent completions can be used to regulate flow from various perforation intervals or producing laterals.
Our recent field studies required the simulation of special wellbore dynamic behavior specific to horizontal/multi-lateral wells. It is a significant challenge to capture such behavior in a simulation model. This paper covers the following issues of horizontal/multi-lateral well simulation.
Special horizontal well flow dynamics exist that are associated with undulations in the wellbore trajectory and consequent fluid holdups. This can result in certain dynamic flow behavior which affects pressure and, consequently, production near the toe. Interference between individual laterals in a well. The use of inflow control devices such as intelligent completions with regulating valves that regulate production from specific perforated intervals/laterals.
The simulation of these issues requires special techniques, such as the use of a discritized well model. A discritized well is represented by multiple segments along the path of the wellbore. This option provides flexibility in the control of appropriate parameters by segment to properly simulate the different issues that arise with horizontal/multi-lateral wells. In addition, local grid refinement is often needed to accurately capture the well trajectory and detailed fluid flow and pressure profiles.
This paper discusses the previously mentioned horizontal/multi-lateral well fluid and completion dynamics and the approach used to simulate them. Simulation results for successful actual field studies as well as semi-synthetic examples are presented.
Identification of Wells with High CO2-Leakage Potential in Mature Oil Fields Developed for CO2-Enhanced Oil Recovery
Authors: Watson T. L. , Bachu S. 
Published: April 2008

Abstract
Previous work, presented in SPE 106817, "Evaluation of the Potential for Gas and CO2 Leakage along Wellbores", described a method to predict the potential for wellbore leakage which primarily occurs in the shallow areas of a wellbore.
The work presented here focuses on the potential for leakage to occur from the deep regions of a wellbore, particularly from viable oil reservoirs. The potential for wellbore leakage where CO2 emhanced oil recovery (EOR) or sequestration is or may be conducted is specifically investigated.
The Alberta Energy Resources Conservation Board collects and maintains data regarding cement types used in primary cementing of casing strings, stimulation information and abandonment data. These data were used to determine the potential for deep wellbore leakage in the presence of CO2. This deep wellbore leakage potential is then coupled with shallow wellbore leakage potential to predict which wells may leak to other reservoirs, potable groundwater aquifers or to the atmosphere in a CO2 sequestration or EOR project.
Cements with additives such as bentonite have been shown to be particularly susceptible to CO2 attack. Wells were screened for cement blends placed in the deeper sections of the wellbore during primary cementing. This information is useful in predicting if a wellbore will remain leak free if CO2 is placed in the reservoir and the wellbore is contacted.
The stimulation method was evaluated to determine if injected CO2 may break through to existing wellbores prior to full reservoir sweep, thus decreasing the time that the wellbore could remain leak free. Stimulations such as hydraulic fracture, perforating and acidizing with pressure were deemed to increase the likelihood that wellbores would leak due to cement sheath cracking coupled with CO2 attack of cement and casing.
The abandonment method was also evaluated. In Alberta the primary form of zonal abandonment utilizes a mechanical bridge plug capped with cement. The bridge plug material is expected to fail in the presence of CO2 due to CO2 attack on elastomers and cast iron.
Two large field evaluations are presented as case studies.