bluuebunny/crossref_metadata_2025 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

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

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

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

Implantation 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

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

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

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

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

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

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

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

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.
Understanding the Rate of Clean Up for Oil Zones after a Gel Treatment
Authors: Seright R. S. , Lindquist W. Brent , Cai Rong
Published: April 2008

In our previous work, X-ray computed microtomography (XMT) was used to establish why pore-filling Cr(III)-acetate-HPAM gels reduced permeability to water much more than to oil. Our results suggest that permeability to water was reduced to low values because water must flow through gel itself, whereas oil pressing on the gel in a porous medium forced pathways by dehydration—leading to relatively high permeability to oil. Those studies involved obtaining 3D pore-level X-ray images at the saturation endpoints—for example, after forcing 20 pore volumes of oil or water through the core following gel placement.

The dependence of oil permeability on oil throughput determines how long it takes for a production well to "clean up" or restore productivity after a gel treatment. Consequently, we were interested in how the gel dehydration process progresses as a function of oil throughput. This paper describes a new study where pore-scale XMT images were obtained at a variety of oil (hexadecane) throughput values after gel placement (involving a pore-filling Cr(III)-acetate-HPAM gel). For each pore in our image volume, we followed oil and water saturations as a function of oil throughput. These studies were performed both in water-wet Berea sandstone and in hydrophobic porous polyethylene. In hydrophobic porous polyethylene, oil saturations increased and gel was destroyed (presumably dehydrated) quite quickly in the smallest pores (10−6 mm3). Also, oil saturations increased and gel was destroyed quickly in the largest pores (<0.005 mm3). In contrast, oil saturations rose much more gradually for the most common or intermediate-sized pores (around 10−4 mm3, the peak in the pore size distribution). The minimum in oil saturation versus pore size may result from a balance between gel dehydration by oil film growth versus gel extrusion. Presumably, during oil injection after gel placement, an oil film forms with a thickness that is about the same on all polyethylene surfaces. However, because the ratio of film thickness to pore or throat size increases with decreased pore size, gel dehydration occurs faster and more effectively in the smallest polyethylene pores, causing oil saturation to increase with decreased pore size. This effect may lose its signicance for pore sizes above 10−4 mm3. As pore size increases above 10−4 mm3, gel extrusion from the pore becomes more likely—explaining why oil saturation increased with increased pore size for the largest pores.

In contrast in water-wet Berea sandstone, increases in oil saturation occurred evenly over all pore sizes (10−6 to 0.02 mm3) for all oil throughput values. Consistent with imbibition and drainage studies performed before gel placement, oil apparently had equal access to Berea pores of all sizes, and thus uniformly dehydrated gel in pores of all sizes. Gel extrusion did not appear to be significant in the Berea pores.
Time-Lapse Seismic Used to Qualify the Drainage and IOR Strategies on the Snorre Field
Authors: Aanvik Frank , Tønnessen Randi Kristin , Aurvåg Roar , Brustad Gro Valle , Lyse Ottar , Kollbotn Lars
Published: April 2008

Hypothesis associated with drainage and IOR strategies are often justified theoretically or by small scale experiments. The effectiveness of reservoir development measures is therefore often uncertain.

The Snorre field is a large North Sea oil field with a thick, heavily faulted, eroded and heterogeneous (fluvial) reservoir with a complex production history with a large IOR potential. The field's economy relies on an effective IOR strategy.

A multidisciplinary time-lapse seismic interpretation project has been carried out. A workflow was designed where all data types, models, tools and disciplines were integrated in the analysis, documentation and presentation of results. 3D Geobodies populated with difference seismic amplitudes were imported in relevant software's for visualization and analysis.

The analysis has been done by a dedicated project team, while close cooperation with operational teams and applicants of the results has assured that results incorporate detailed operational experience and are properly implemented and quality assured.

Aside from producing explanations to individual seismic effects, observations were used to support or weaken hypothesis relating to the drainage and IOR strategies.

The results are integrated qualitatively in the history matching, and adjustments due to 4D information gave significant improvements. A fault seal analysis was extended with time-lapse observations. Gas injection is assumed to improve oil mobility as gas dissolves in the oil, which is not always in line with 4D observations. Gas flooding, migration and stacking (attic gas) are better understood from 4D data. Also, bypassed or unswept oil is detectable from the 4D seismic.

The results have already influenced drilling decisions and well interventions. The conclusions will also play an important role evaluating the overall drainage strategy, existing IOR strategy and upcoming IOR initiatives.

The work demonstrated how time-lapse can be taken beyond geophysics to become an integral tool in reservoir development.
Pore Scale Estimation, Up Scaling and Uncertainty Modeling for Multiphase Properties
Authors: Rustad Alf B. , Theting Thomas G. , Held Rudolf J.
Published: April 2008

A workflow incorporating pore space modelling, small scale heterogeneity and uncertainty modelling has been established and successfully employed in a North Sea oil reservoir. The study was performed on a heterogeneous interval of the reservoir, with water flooding as the basic recovery strategy. The geology was characterized identifying relevant scales of heterogeneity. The interval consists of hummocky cross-stratified deposits, with varying contrast and lamination. Consequently, small scale models were built capturing the laminations seen in cores at a scale interpreted to be at a representative elementary volume. Pore space reconstruction and property estimation by pore scale modelling were used to obtain realistic relative permeability and capillary pressure data for each lamination. At each stage of the workflow, a set of models was handled to account for uncertain parameters. Uncertain parameters included porosity, permeability, pore space and lithofacies geometry, and rock/fluid wettability. These parameter uncertainties propagated into uncertainty in the multiphase properties, i.e., relative permeability and capillary pressures. Steady-state multiphase upscaling was used to obtain multiphase properties representative for the geo-cellular model scale. The multiphase flow properties generated from pore scale modelling and upscaling were incorporated in an interwell-scale model with a geo-cellular grid resolution, and simulations compared with a base case model with traditional multi-phase flow properties. The updated model demonstrated altered flow behaviour and sweep, which were consistent with field observation. More precisely it showed a water override with by-passed oil in the lower parts of the model, a behaviour which was not adequately captured in the base case model. Moreover, the modified flow physics were relatively easy to implement and could be run with little additional computational cost in the full field simulation model. As the results constitute key information for reservoir monitoring and for improving oil recovery, the operational full field model was updated to include these findings.
Utilizing Acidized NH2 for Mitigating Formation Damage and Improving Oil Recovery: Case Study of Penara Field, Malaysia
Authors: Agil N. A. M. , Saaid I. M. , Ibrahim J. , Harun M. F.
Published: April 2008

Deposition of solid hydrocarbons such as asphaltene and wax near the wellbore and in the tubing is known to cause decline in the well production performance. Various mitigation methods such as chemical wax inhibition, thermal insulation, and coiled tubing clearance are repetitive and exhaustive. These methods could temporarily remove deposits but not prevent them from reoccurance. On the other hand, the thermo-chemical method utilizing acid-base reactions seems to be offering the most effective and simple solution to the problem. Reaction products and heat from the acid-base reactions could be utilized to dissolve and disperse wax or asphaltene deposition in addition to changing the wettability profile. The present study is to evaluate the performance of acidized amines for mitigating formation damage and improve oil recovery in the Penara Field, offshore Peninsular Malaysia. Wells in the field have been recording massive production decline of more than 5000 stb/d despite continuous treatment of pour point depressant, wax dispersant, de-emulsifier and frequent tubing clearance activities.

Physical observation and interfacial tension measurement were carried out to qualitatively and quantitatively measure the performance of the acidized amines. Improvement in the oil recovery was measured through coreflooding test. The study found that acidized amines by-products dispersed the suspended wax solid and prevented it from re-depositing after 48 hours. Thus, oil recovery increased to 51.3 % for non waxy-liquid crude and 13.0 % for waxy-gelled crude. These findings from the laboratory were further validated by production optimization using Wellflo.

The thermochemical method utilizing acidized amines is simple and yet experimentally proved to be effective in solving the wax related problem. Considering the reserve potential in the Penara Field and supported by sufficient well data, the incremental production of 22 % could be predicted.
A New Method for Vertical Leak Detection in Low to Moderate Permeability Flooded Reservoirs
Authors: Walser D. W. , Astakhov D. K. , Stanley G. R.
Published: April 2008

Rising commodity prices have resulted in an increase in secondary recovery projects that are associated with lower permeability reservoirs. These processes often inject fluids above the parting pressure for the duration of the life of the flood, and pressurization takes place as fluids leak off from the exposed surface area of the induced fracture into the surrounding moderate or low-permeability reservoir matrix. The primary difference between these situations and conventional flooding is that matrix fluid migration is initiating off an induced fracturing plane, as opposed to point-source initiation.

During the early history of a flood, mass-balance issues are often ignored, as average reservoir pressures are typically low, and injection rates can dramatically exceed production. As pressures rise, some localized portions of the reservoir not only can exceed virgin static pressures, but volumes near existing induced fractures can approach or equal the pressure in those fractures. When this occurs, vertical fracturing can be initiated, either above or below the reservoir, depending upon the location of the closest lower stress interval.

A new method to detect the location of vertical "leakage" has been developed. This method utilizes existing Surface Tiltmeter (STM) technologies and a new surface deformation calculation regime to zero in on volumetric changes that occur above or below the limits of the given reservoir. This method uses measured surface deformation from observed tilt to extrapolate the volumetric change at different specified depths. With a number of constraints, and using a linear geophysical model based on poroelastic equations, an inversion routine is used to find the reservoir compaction or expansion at different depths. When volumetric change best fits the measured deformation data (or tilt) at the surface, the depth and aerial location is then correlated to the area near a specific well or wells.
Economics of Field Proven Chemical Flooding Technologies
Authors: Wyatt Kon , Pitts Malcolm , Surkalo Harry
Published: April 2008

Chemical enhanced oil recovery technologies are field-proven methods that improve overall oil recovery. High oil prices and dropping reserves replacement has stimulated interest in these technologies, particularly for application in mature waterfloods. Depending upon the perspective of investors, the decision to proceed with an oil field project may depend upon projected: Rate of Return, Return on Investment, $/bbl of added reserves, cumulative cash flow, or combinations of these. This paper discusses chemical flooding processes, constraints on application, and presents economic impacts of: injected chemical cost, oil price, chemical concentration, oil recovery, and process time. The alkaline-surfactant-polymer technology is compared with micellar flooding and alkaline-polymer flooding. For example, a typical range of chemical costs per barrel of added oil for an Alkaline-Surfactant-Polymer project would be $3.50/bbl to $12/bbl for oil recoveries ranging from 0.2 PV down to 0.05 PV (or approximately 25% OOIP to 6.25% OOIP). Rate of Return (ROR) and payout time depends upon process rate, or pore volume per year of injection. Chemical flooding places the majority of cost over the first 50% pore volume of injection whereas, oil incremental income is delayed until the developing oil bank reaches production wells. In today's oil price environment of >$40/bbl, chemical flooding technology provides significant financial returns with increased ultimate oil recoveries.
Advanced Wells: How are they Being Used and are they Creating Value?
Authors: Mitchell Anthony F. , Skarsholt Line T.
Published: April 2008

By December 2007 eighty three wells, in twenty three StatoilHydro operated fields in the North Sea, were equipped with advanced completions. These wells (which include vertical, horizontal and multilateral reservoir sections) typically have a completion which consists of instrumentation in combination with one or more, remotely (surface) operated, downhole valve. Levels of instrumentation varies, from the complex - with internal and external pressure and temperature gauges in several reservoir zones - to the simpler, with only one pressure and temperature gauge on top of the reservoir.

Since the completion of the first advanced well in 1997 the Company has now gained experience with more than two hundred remotely operated downhole valves and is further developing the potential of advanced completions. Some assets have been able to make more use than others of the potential offered by the technology. This paper presents a review of how advanced wells are being used, the added value generated through their use and the additional potential they can offer.
A Mathematical Model for Emulsion Mobilization and Its Effect on EOR During ASP Flooding
Authors: Lei Zhengdong , Yuan Shiyi , Song Jie , Yuan Jiangru , Wu Yu-Shu
Published: April 2008

Large-scale pilot tests of alkali-surfactant-polymer (ASP) flooding in the China's Daqing Oilfield reveal that emulsification occurs during ASP flooding and displacement. The flow of emulsions in porous media exhibits high viscosity, well-behaved chemical stability, and apparent non-Newtonian flow features. The genesis and mobilization of emulsions in reservoirs are an important part of ASP flooding processes, and entrainment and capture of such emulsions in porous media are considered to be important for improving oil recovery by ASP flooding. However, there are few studies that attempt a quantitative description of emulsion mobilization in porous media. As a result, the physicochemical phenomena of emulsions are not included in the current numerical simulation of ASP flooding processes.

Based on our experimental studies and field tests, we conducted an in-depth analysis of displacement mechanisms, emulsification, and flow behavior of emulsions in porous media during ASP flooding processes. In this paper, we describe the development of a mathematical model to describe such physicochemical emulsion phenomena. This mathematical model incorporates the mechanisms governing the interaction between emulsion droplets and pore structures, including emulsion genesis criteria, correlation of emulsion viscosity and water content, and permeability reduction caused by droplet capture. The model is implemented into an existing chemical reservoir simulator for numerical modeling studies of ASP flooding that considers emulsification mechanisms. Simulation results show that oil emulsification during ASP flooding has a significant impact on, and could improve, in situ oil displacement efficiency. The proposed model can be used for understanding the effects of emulsions in ASP flooding, within both laboratory studies and field applications.
Laboratory Evaluation of Water-Swellable Materials for Fracture Shutoff
Authors: Abbasy Imran , Vasquez Julio , Eoff Larry , Dalrymple Dwyann
Published: April 2008

The existence of high permeability features such as fissures, fractures, and eroded out permeability zones, diminishes the sweep efficiency of any water, gas, or polymer flooding. This paper presents the laboratory evaluation of three water-swellable materials (WSM) that can be bullheaded into the well to shut off fractures. The WSM, which swell on contact with water, would be mixed on-the-fly, entering fissures and fracture systems as they swell without invading the matrix of the rock. The rate of absorption can be controlled based on the particle size, carrier fluid, and formation fluid. This conformance technology is also applicable to address circulation-loss problems in production and injection wells.

The following materials were evaluated: (1) a polyacrylamide polymer, (2) a chloroprene rubber, and (3) a nitrile rubber. The polyacrylamide polymer is capable of absorbing 30 to 400 times its own weight in water while the two rubbers swell approximately 5 to 10 times their original weight. The WSM were evaluated for effectiveness to: (1) provide controllable swelling rates at different conditions, (2) shut off the flow of water in synthetic cores with simulated fractures at 135°F, and (3) provide long-term thermal stability in H2S and CO2 environments. In addition, the capability of the polyacrylamide polymer to withstand differential pressure was evaluated over time in a core-flow experiment.

Discussed are: (1) the methodology used for measurement of swelling properties for each material at different conditions including carrier fluid, particle size, and temperature, and (2) core-flow tests with simulated fractures. These materials are nontoxic and do not contain heavy-metal crosslinkers. Based on this study, these materials present an innovative technology for fracture shutoff and to help control circulation-loss problems. In addition, these materials are resistant to acid contamination in CO2 and H2S environments.
Application of a New Fully-Coupled Thermal Multiphase Wellbore Flow Model
Authors: Livescu S. , Durlofsky L. J. , Aziz K. , Ginestra J. C.
Published: April 2008

Thermal recovery processes are widely applied for the production of heavy oil and oil sands. Thermal reservoir simulation models, however, often lack a comprehensive well modeling capability. Such a capability is required to capture the detailed thermal effects that occur in the wellbore. These effects can be important as they impact wellbore pressure and temperature and thus production and injection. We recently developed a fully-coupled black-oil thermal multiphase wellbore flow model and implemented it into Stanford's General Purpose Research Simulator (GPRS). The model computes pressure, temperature, and oil, water and gas phase fractions along the wellbore as a function of time and includes treatments for slip between fluid phases, heat losses to the reservoir, and general variations of fluid properties with temperature and pressure. The purpose of this paper is to validate and test the coupled wellbore-reservoir model for challenging and realistic cases. The thermal wellbore model is first validated through comparison to field data for three-phase flow in a long well with both vertical and inclined sections. Close agreement between the model and field data is obtained. Complex wells containing multiple branches are then simulated, including a steam-water case with vaporization and condensation. The general conclusion from this work is that the new model is capable of simulating a wide variety of complex coupled reservoir-wellbore phenomena.
Performance Analysis of SAGD Wind-Down Process with CO2 Injection
Authors: Bagci A. S. , Olushola S. , Mackay E.
Published: April 2008

Thermal recovery methods involving steam injection have long been considered as an effective means of extracting heavy oil resources. In addition, the high recovery performance of SAGD makes it a popular option for these non-conventional oil resources. Steam processes are energy intensive and result in generation of emissions which are detrimental to humankind and the environment. The use of non-thermal processes involving CO2 as a miscible or immiscible gas phase in combination with steam for heavy oil recovery is considered as a viable alternative to limit the drawbacks of steam generation. These processes have the capability to enhance oil recovery through CO2 utilization during production and also provide an avenue to dispose CO2 after production. Numerical simulation studies have been carried out utilizing STARS (a three phase, multi-components reservoir simulator) to optimize a baseline SAGD process and wind-down process with CO2 Injection. The baseline process was operated until maturity then CO2 injection was used to initiate wind-down after 4, 6 and 8 years of a 12 year production operation. Following each of the wind-down processes, CO2 disposal was undertaken for 25 years and the storage potential evaluated. The baseline SAGD process had a recovery factor of 76%. The SAGD wind-down processes with CO2 injection after 4, 6 and 8 years had recovery factors of 54%, 77% and 79% respectively. This and other parameters proved the feasibility of SAGD wind-down process with CO2 injection and its potential to enhance oil recovery.
Buffalo Field High-Pressure Air Injection Projects: Technical Performance and Operational Challenges
Authors: Gutiérrez D. , Miller R. J. , Taylor A. R. , Thies B. P. , Kumar V. K.
Published: April 2008

The Buffalo Field air injection units, located in northwest South Dakota, are the oldest High-Pressure Air Injection (HPAI) projects currently in operation.

In mid 1977, realizing the rapid production decline under primary recovery, the operator initiated an IOR program including laboratory tests, feasibility studies, and a pilot air injectivity test. Because the pilot results were promising, the original 3.5-section Buffalo Red River Unit (BRRU) was formed in September 1978. The results continued to be encouraging and the unit was enlarged to nine sections in September 1980 and to twelve sections in May 1981. Based upon the success of the BRRU HPAI project, the South Buffalo Red River Unit (SBRRU) of 30.5 sections was formed in June 1983 and began to respond to injection in 1985. Furthermore, given the success of the BRRU and SBRRU HPAI projects, the 7-section West Buffalo Red River Unit was formed and started air injection in November 1987.

This paper summarizes the performance of the three projects and the overall experience gained by the operators after nearly 30 years of air injection. It covers almost every aspect of the entire operation since its inception; it discusses general management practices, technical and operational challenges encountered, injection and production facilities and drilling and well completion practices. It also includes estimates of incremental oil recovery due to air injection and discusses how the air utilization has changed over time

To date, the three HPAI projects in the Buffalo Field continue to be a commercial success. In the last three years, horizontal laterals have been drilled out of over 40 old vertical wells to enhance production, to take advantage of accumulated reservoir energy and to improve sweep efficiency. Drilling injection wells out of old vertical wells was not possible because the open hole laterals cross a porosity zone that would have taken away some of the injection into non-productive reservoir.
Retention of CO2-Foaming Agents Onto Chalk: Effects of Surfactant Structure, Temperature and Residual Oil Saturation
Authors: Fjelde Ingebret , Zuta John , Hauge Ingrid
Published: April 2008

Injection of CO2 is a well known enhanced oil recovery (EOR) technique. Formation of stable foam inside the reservoir can improve macroscopic sweep efficiency. On the other hand, retention of surfactants decreases the cost-efficiency of the EOR process. This paper presents flow-through retention experiments with CO2-foaming agents onto outcrop Liege chalk plugs. Two branched ethoxylated (EO) sulphonates with different ethoxylation degree, S1 (EO=7) and S2 (EO=12) were used. The aim was to investigate the effect of ethoxylation degree on surfactant retention. Furthermore, the effects of temperature and residual oil on surfactant retention were studied. The effect of waterflooding followed by CO2 flooding on surfactant retention at reservoir conditions was also evaluated. Partitioning of the foaming agents between water and oil phases was studied.

Results show that increasing the ethoxylation degree of the surfactant decreases the retention onto chalk cores saturated with formation water at 55°C. S2 (EO=12), which was found to give the lowest retention at 55°C, was found to have a higher retention at 70°C. The presence of residual oil saturation after waterflooding (Sorw) decreased the retention of S1 (EO=7) and increased the retention of S2 (EO=12) when compared to the absence of residual oil. The retention of S2 (EO=12) after waterflooding followed by CO2 flooding at 340 bar and 55°C was in the same range as retention on 100% water saturated core, but significantly lower than retention in residual oil saturated cores. The experiments have shown that not only surfactant structure and temperature are important for the retention of surfactants, but also the presence of oil.