bluuebunny/crossref_metadata_2025 huggingface dataset:
Experimental Investigation of In Situ Combustion at Low Air Fluxes
Authors: Alamatsaz A. , Moore R. G. , Mehta S. A. , Ursenbach M. G.
Published: May 2011

The oil industry has inherited a mixed history of success and failure of application of air injection as an enhanced oil recovery method. Close scrutiny of these projects shows that in order to conduct a successful in situ combustion oil recovery project, sustained propagation of the combustion front within the reservoirs is a must. Sufficient air must be supplied to maintain the propagating combustion front in the desired bond scission (carbon oxide forming) mode otherwise unfavorable oxygen addition i.e. Low Temperature Oxidation (LTO) reactions will consume oxygen and not mobilize oil. When this happens, the combustion process is deemed to be exhausted.

Quantification of the minimum air flux required for sustaining combustion zone propagation is needed to properly match the capacity of the air injection facility to the volume of reservoir which is to be swept by the thermal zone. Undersizing of the air injection capacity causes the in situ combustion process to become inefficient when only a small portion of the reservoir has been "burned".

One-dimensional combustion tubes (CTs) are conventionally used to obtain important combustion parameters required for designing an air injection project. Due to the high heat capacity of laboratory equipment designed for elevated temperature and pressure operation, oxygen addition or LTO reactions are promoted by the heat transfer through the core holder walls when the laboratory tests are performed at low air injection rates. Therefore, when operated at elevated pressures, the CTs are unable to operate at the low air fluxes required to establish the minimum possible air injection flux while maintaining the combustion reactions in an effective mode.

To address this issue, a state of the art combustion cell was conceived and utilized as a way of addressing the above mentioned constraints associated with high pressure one-dimensional combustion tubes. A conical combustion cell design was built as it enables continuous air flux reductions without having to adjust the air injection rate. The heater control strategy was also modified in order to address the lag-lead operation often used for one-dimensional combustion tubes. To date, the unit has operated at air fluxes down to 3 sm3/m2∙h.

This experimental work described in this paper provides insight into the limitations in laboratory investigations of in situ combustion as well as the expected behavior of field applications of the in situ combustion process.
Recovery Mechanism of Steam Injection in Carbonate Reservoir
Authors: Tang Guo-Qing , Lowry Dustin , Lee Vincent
Published: May 2011

Thermal processes application in carbonate heavy oil reservoir is less successful than sandstone reservoir due to its feature that is naturally fractured and oil-wet condition. The enhanced oil recovery by steam drive in carbonate reservoir is often low because the steam easily bypasses oil which is locked in low permeability matrix. In addition, the recovery mechanism by steam injection is not well understood so far. The research from last decade showed that recovery mechanism is dominated by complicated interactions between oil/brine/rock and mineral heterogeneity. Imbibition and drainage may dominate the heavy oil recovery from fractured carbonate reservoirs when the steam is injected.

This work presents an experimental study that was designed to characterize the recovery mechanism of steam injection in heavy oil carbonate reservoir by simulating the reservoir conditions. Several reservoir rock samples with a length of 3 inches and a diameter of 1.5 inches were used for both free and forced imbibitions at elevated temperatures. The crude oil from the same formation has an API gravity of 14 and a viscosity of 5624 cp at room temperature was used as oil phase. The water phase was either synthetic formation brine or 5000 ppm NaCl brine. A high resolution CT scan imaging technology was used for screening core candidates and cutting the core plugs to avoid a significant difference in core properties which may affect recovery mechanism.

This study revealed that the oil recovery from carbonate reservoir by steam flooding is mainly dominated by imbibition, viscosity reduction, and in-situ steam generation inside the core. The increase in imbibition oil recovery is strongly dependent on the interaction between the oil/brine/rock which in turn affects the wettability rock. Effluent brine chemistry analysis verified that carbonate dissolution is associated at a temperature above 300°F, which may result in wettability alteration toward water-wetness. The oil recovery by free imbibition increased from around 10% OOIP to 50% OOIP as the temperature is increased from 100 to 400°F. If the pore pressure is suddenly reduced from 350 psi to room atmosphere pressure at 400°F (in-situ flashing process), the oil recovery can be further increased to 60–70% OOIP due to a significant amount of steam is generated in-situ. Correspondingly, the rock compaction is observed during the flashing process. The measured rock compaction is less than 4% of the total pore spaces. Compared with free imbibition, forced imbibition at low temperature gives higher oil recovery at low temperature, but does not show significant increase in oil recovery at high temperature.
Thermally Induced Fracture Reconsolidation of Diatomite Under No Flow Conditions
Authors: Vega B. , Tang G. Q. , Kovscek A. R.
Published: May 2011

Diatomite reservoir rocks are characterized by high porosity (35–70%), low permeability and have a favorable response to thermally enhanced recovery methods. Fracture reconsolidation or healing occurs, in some cases, during heating of diatomite. Silica dissolution is considered one of the main mechanisms that leads to fracture consolidation. Alkaline brine solutions have been found favorable to silica dissolution and therefore, fracture healing. The objective of this work is to delineate the impact of the application of elevated temperatures and confining pressure under no flow conditions on core-scale fracture reconsolidation of fractured diatomite samples where the silica is in either opal-A or opal-CT phases. A series of isothermal experiments was conducted over a range of temperatures between 45 and 230 °C, a range of confining pressures between 100 and 700 psi, and minimum flow of brine as the aqueous phase. Fractures were created parallel and normal to the core length. Fracture reconsolidation was verified as reflected by changes in permeability and porosity of the samples, by image analysis provided by CT scan X-ray tomography and by visual inspection after the tests. Increasing temperature resulted in a trend of decreased permeability as the result of the permeability loss due to compaction and reconsolidation of the fractured area. Results suggest that fracture healing in diatomite occurs even under minimum aqueous phase conditions, when combined with a dose of confining pressure and elevated temperatures.
Is there a "Silver Bullet Technique" For Stimulating California's Monterey Shale?
Authors: Shaari Nabil E. , Minner W. A. , LaFollette R. F.
Published: May 2011

A large number of California's Central Valley, coastal, and offshore oilfields produce from the Miocene Monterey shale formation. Example oilfields with productive Monterey intervals include offshore and inland fields such as Hondo, Point Arguello, Lost Hills, Elk Hills, Belridge, and North Shafter/Rose. Example productive formation members that produce from the Monterey shale would include the Antelope Shale, McLure shale, McDonald Shale, and the Reef Ridge. The Monterey shale is both a reservoir and hydrocarbon source rock. There are large variations in reservoir properties and general interval behavior due to differences in the lithology, diagenetic state, mechanical properties, and the stress state. Generally the Monterey shale has a low matrix permeability of 0.01–1.0 md, but effective permeability can be higher due to natural fracture conductivity. Porosity spans a huge range – from as low at 10% to as high as 70%.

One illustrative example is in Southeast Lost Hills, where vertical wells are drilled and hydraulically fractured to target thick Opal-CT and the deeper cherty/quartz-phase Monterey pay intervals. The design and placement of multiple fracture treatment stages with appropriate conductivity and half-length is a requirement for a successful field development. In contrast, offshore Monterey developments have usually targeted intersecting the conductive natural fracture network in quartz-phase intervals. For this flavor of the Monterey, an acid job can effectively stimulate production by removing the drilling/completion damage and dissolving the calcite filling in natural fractures.

A significant thickness of Monterey siliceous shale is present across a large area in California. The oil industry has learned much from unconventional shale reservoir development elsewhere in the country. Is it possible that Monterey siliceous shale will be transformed into the California version of an ‘unconventional’ shale resource? The key will be to identify the Monterey intervals with the most potential, and apply the proper development drilling and completion strategy, with changes made to accommodate the low-mobility multiphase liquid flow. General Monterey development challenges include: a) defining the structure, b) identifying the target pay intervals within the thick depositional intervals, c) understanding the lithology and the reservoir / rock properties of the different pay zones, d) understanding and designing the optimum stimulation treatment(s) and e) determining the optimum well development pattern and completion strategy to incorporate all the above requirements. Is there a "silver bullet" strategy that will enable success in the pervasive Monterey siliceous shale? The purpose of this paper is to stimulate industry thought and discussion.
Comparing the Results of a Full-Scale Buckling Test Program to Actual Well Data: New Semi-Emprical Buckling Model and Methods of Reducing Buckling Effects
Authors: Mitchell Sarah , Moore Norman Bruce , Franks James , Liu Gefei , Yang Yanghua
Published: May 2011

Buckling and its effects are topics of economic and technical interest as ERD and horizontal wells become critical to maximizing recoverable reserves, particularly in the Continental United States and Alaska. Previous work has resulted in important discoveries about drill string buckling, but to date, little testing has been done on actual drill pipe in a controlled manner, particularly in measuring drill string whirl. As a result, there can be disparities between theoretical predictions of buckling effects versus actual field results. These disparities can result in unrealistically high friction factors required to bring calculated values close to actual data, or in many cases, operational difficulties such as high torque, low ROP, drill string failures, inability to maintain directional control, or reach the planned depth can result.

To learn more about drill string behavior in buckling conditions, a full-scale buckling test fixture was developed to evaluate the effects of buckling on 2 ⅞−, 3 ½−, and 4-inch drill pipe while sliding and rotating inside 7 inch casing. The test fixture incorporated a variety of sensors and cameras to characterize torque, drag, vibration, and drill string deformation under buckling loads. As part of the test program, low friction non-rotating protectors were also tested to measure performance under buckling conditions.

The test results show that drill string buckling occurs at far lower loads than predicted by current models, possibly caused by minor deformations inherent in real drill pipe. The results also show that for a given amount of torque or drag, protectors increased the available compressive load by 20 to 30% and substantially reduced vibration caused by drill string whirl.

The test results were used to develop a new Semi-Empirical Buckling Model that predicts contact forces resulting from drill string buckling and also the torque and drag effects of drill string whirl. This model was then incorporated into torque and drag modeling software where it was compared against actual data from a large number and variety of wells. The results show an ability to more accurately predict torque, drag, and vibration caused by buckling and whirl.
New Experimental Model Design for Systematic Investigation of Capillarity and Drainage Height Roles in Vapor Extraction Process
Authors: Ahmadloo F. , Asghari K. , Henni A. , Freitag N. P.
Published: May 2011

Vapor Extraction is a solvent-leaching gravity drainage-based process that can be used for improving recovery factors from0020low-pressure heavy oil and bitumen reservoirs. Despite numerous experimental and numerical studies having been conducted, the associated production mechanisms in this process are still poorly understood. This paper presents the details of a new experimental approach that can overcome limitations of previous physical models for representative simulation of capillarity and drainage height effects on performance of the vapor extraction process. Unlike other studies in literature, the physical models in this study were designed to provide a constant composition solvent surface at one face of the heavy oil saturated sandpack. To eliminate the effect of pressure surges, a new effluent collection system was successfully designed and tested. This experimental setup made it possible to study the interplay between the selected parameters on stabilized drainage rates under effects of capillary and gravity forces. Here, a comprehensive experimental study was conducted in two 2D visual physical models using Plover Lake oil from west-central Saskatchewan and n-butane as solvent in the permeability range of 5.1–6.5D. This paper discusses the significant effects of capillarity and drainage height on the stabilized drainage rates, Vapex dimensionless number, and efficiency of mass transfer phenomena in the Vapex process. This study provides in-depth knowledge necessary for developing more reliable mass transfer models to depict the vapor extraction process in the presence of capillary forces.
Numerical Optimization of Clearwater Formation's Response to SAGD under New Well Configurations
Authors: Tavallali M. , Maini B. , Harding T.
Published: May 2011

The Cold-Lake oil sands contain the second largest reserves volumes among the oil sands deposits in Canada. The bitumen and heavy oil are contained in various sands of the Lower Cretaceous Mannville Group – Clearwater Formation.

For the past 30 years, Cyclic Steam Stimulation (CSS) has been the commercial thermal recovery method employed in the Cold Lake area. More recently, Steam-Assisted Gravity Drainage (SAGD) has been field tested in number of pilot projects at Cold Lake. Although SAGD has been demonstrated to be technically successful and economically viable, questions remain regarding SAGD performance compared to CSS. A more comprehensive understanding of the parameters affecting SAGD performance in the Cold Lake area is required. Well configuration is one of the major factors which require greater consideration for process optimization.

This paper presents a numerical simulation investigation of the impact of using several modified well configurations for SAGD in the Clearwater Formation in Cold Lake area in order to improve the process performance. The technical feasibility of applying each arrangement was evaluated through sensitivity analysis using a fully implicit reservoir thermal simulator (CMG STARS 2009.13). In order to account for frictional pressure drop and heat losses along the wellbore, the fully coupled wellbore/reservoir (discretized wellbore) model was utilized during the course of this study. The reservoir and fluid properties were selected to represent the main bitumen production area at Cold Lake.

The new well configurations provide operational and economical enhancement to the SAGD process over the standard well configuration (a horizontal injector lying approximately 5 meters above a horizontal producer) in Cold Lake area. The SAGD process response to different reservoir parameters of the Cold Lake Formation, such as initial injectivity, mobile water saturation, and reservoir heterogeneity has been investigated for the most promising of the new well configurations.
Upscaling for Field-Scale In-Situ Combustion Simulation
Authors: Zhu Z. , Bazargan M. , Lapene A. , Gerritsen M. , Castanier L. , Kovscek A.
Published: May 2011

In traditional thermal reactive reservoir simulation, mass and energy balance equations are solved numerically on discretized reservoir grid blocks. The reaction terms are calculated through Arrhenius kinetics using cell-averaged properties, such as averaged temperature and reactant concentrations. The chemical reaction front is physically very narrow, typically a few inches thick. To capture accurately this front, centimeter-sized grids are required that are orders of magnitude smaller than the affordable grid block sizes for full field reservoir models. We propose a new method based on a non-Arrhenius kinetic upscaling approach. We do not resolve the combustion front on the grid, but instead use a subgrid-scale model that captures the overall effects of the combustion reactions on flow and transport, i.e. the amount of heat released, the amount of oil burned and the reaction products generated. The subgrid-scale model is calibrated using fine-scale highly accurate numerical simulation and laboratory experiments. This approach significantly improves the computational speed of in-situ combustion simulation as compared to traditional methods. We are currently developing a field-scale simulator using the above ideas. Test cases illustrate the solution consistency when scaling up the grid sizes in multidimensional heterogeneous problems. The methodology is also applicable to other subsurface reactive flow modeling problems with fast chemical reactions and sharp fronts.
A Three-Parameter Dual Porosity Model for Naturally Fractured Reservoirs
Authors: Jabbari Hadi , Zeng Zhengwen
Published: May 2011

This study presents a new model to analyze the behavior of naturally fractured reservoirs (NFRs). The model considers the geomechanical behavior of the fractured reservoirs and the corresponding effects on the fracture aperture, which may be an important parameter for stress-sensitive NFRs. It includes the elasticity parameters, such as Poisson's ratio and Young's modulus.

Pressure depletion in an NFR, inherent to production, can result in effective stress change that, in turn, may change fracture permeability in NFRs. This may influence the behavior of NFRs, which has been studied thoroughly in the literature; however, not analytically but only numerically. A rigorous mathematical model is developed in this study which couples geomechanical and fluid flow aspects for characterizing a stress-sensitive NFR. In the model, we consider a semi-infinite radial flow with flux boundary conditions at the wellbore (Neumann condition) and constant pressure at infinity (Dirichlet condition). It is also assumed that the external forces acting to the reservoir are constant, that there is interaction between the two regions, i.e. matrix and fracture system, via the change of pore pressure and effective stress.

Since the change in effective stress induced by reservoir compaction may affect the pressure buildup curves in NFRs, new equations on buildup interpretation are developed to better understand this effect, and to precisely evaluate the reservoir properties. An iterative algorithm is also developed which enables us not only to interpret the buildup data to compute the fracture parameters, namely fracture porosity, fracture permeability, fracture storage capacity, and the elasticity parameter, but also to evaluate them more accurately. Such a new technique improves NFR characterization through the inclusion of the fourth dimension, time, into buildup interpretation. This new well test interpretation method is a dynamic reservoir characterization, which is usually the mission of time-lapse (4-D) multicomponent seismology.

From this study, we found that knowing three parameters is sufficient to both distinguish a reservoir with dual porosity from that of a homogenous one and to characterize a dual porosity reservoir. Two of the parameters represent the fracture storage capacity and matrix-fracture interaction. A third one reflects the effect of both matrix geomechanics and fracture aperture decline on the behavior of NFRs as time progresses. These parameters can be obtained by precisely interpreting drawdown or buildup tests. This solution is applicable to any reservoir containing dual porosity rocks.
World's Deepest Thru-Tubing Electric Submersible Pumps
Authors: Julian J. Y. , Patterson J. C. , Yingst B. E. , Dinkins W. R.
Published: May 2011

This paper describes the development, history, and successful deployment of the world's two deepest Thru-Tubing Conveyed electric submersible pumps (TTCESP's). These are the first TTCESP's deployed inside of 7" casing. ESP's are a form of artificial lift which consists of a pump, motor, and electric cable, typically deployed by a rig and connected to electric power at surface. Their advantage is that they create greater drawdown than other forms of artificial lift, thus achieving higher production rates. However, conventional ESP's require expensive workover rigs to replace pumps, the component that fails most frequently. ConocoPhillips Alaska, Inc. (CPAI) developed TTCESP technology to replace failed pumps raidly and economically. In this system, a rig conventionally deploys the electric cable, motor, and seal sections, with a special latching device for the pump. The pump is pulled and replaced with slickline (wireline) or coiled tubing, eliminating the requirement of a rig.

The original TTC systems were developed for 7-5/8" cased wells. Over the past ~10 years it was common belief that they could not be deployed at the Milne Point Field in Alaska due to the limitations of its smaller 7" 26# cased wells. This paper discusses the enabling technologies that were developed to allow running TTCESP's in 7" casing, including a wellhead spoolpiece and low clearance ESP clamps.

West Sak TTCESP run time data indicates the time between rig workovers will increase from 3.5 to 6 years. Pumps can be replaced for 5–10% of rig costs without the safety and environmental impacts associated with rigs. Additionally, production losses while waiting for a rig are eliminated because slickline and coiled-tubing units are readily available on the North Slope of Alaska. TTC pumps can easily be upsized or downsized to optimize pump flow rate due to changes in production rates. This technology is of interest in areas where rig costs are high, including arctic, remote, and offshore locations. It is also beneficial where rig availability is low.
Outer Concentric String Casing Damage Evaluation: Advancements in Electromagnetic Inspection Data Interpretation for Common North Slope Well Completions
Authors: Burton Joey , Yang Hongying
Published: May 2011

Alaska's North Slope wells are subject to a variety of mechanisms that cause corrosive damage to outer casing strings. These include: (1) near-surface casing damage resulting from the ingress of oxygenated (surface) water; (2) corrosive power fluids pumped down the inner annulus of venturi pump wells; and (3) exposure to formation salt water in intervals of poor cement quality. The importance of maintaining casing integrity for safety and environmental reasons, combined with the high cost of pulling tubing strings on the North Slope create a need for an economical means of evaluating outer casing string integrity with the tubing in place.

The successful use of AC magnetic wave, electromagnetic pipe inspection technology to qualitatively assess outer concentric string casing damage for certain well completions has been well documented for applications on Alaska's North Slope since 2006. Information and conclusions drawn in existing literature are all based on the comparison of tool recordings made in the field to the visual inspection of casings subsequently dug up or removed from the well. While these comparisons illustrate many good correlations between recorded metal loss indications and areas of severe metal loss observed in some completions, there remains a need to better quantify the minimum threshold for the extent of casing damage that can be detected via this method.

This paper presents the results of surface tests conducted on dual concentric string pipe configurations with an array of engineered metal loss features designed to test the tool's response to total volumetric metal loss and the spatial configuration of damage to the outer string. The tool's response to deep pitting on the external surface of the inner concentric string is tested as well. Conclusions are drawn in respect to the approximate size and shape of defects that can be expected to be detected for the concentric pipe configurations tested. The application of this knowledge to data recorded in the field will add greatly to the confidence of risk assessments made with this technology in well work decision processes.
Ranking the Resource Potential of the Woodford Shale in New Mexico
Authors: Bammidi V. S. , Balch R. S. , Engler T. W.
Published: May 2011

The Upper Devonian Woodford Shale ranges from a thickness of 0 ft to 300 ft and is found at depths of 7,000 ft to 18,000 ft in the Delaware Basin. The Woodford is thermally mature over its entire extent in New Mexico: In the deeper parts of the Delaware Basin, it is in the thermogenic gas and condensate window; on the Northwest Shelf and where present on the Central Basin Platform, it is in the oil window (Broadhead 2010). Southeastern New Mexico is subdivided into Regions I, II and III based on the intensity of the fracture networks, thermal maturity and Total Organic Carbon (TOC) (Comer 2005).

Miller's (2010) gas shales ranking scorecard used parameters like total organic carbon, vitrinite reflectance, shale thickness, gas-filled porosity, clay content, quartz content, fluid compatibility, natural fracture intensity, tectonic stress and reservoir pressure gradient. The range of the scale of ranking is 0 to 100 points and for reference, the Barnett has 73 points. The better the total points, the better are the prospects of finding shale gas. Each of the regions (Regions I, II and III) were ranked for the prospects of shale gas using Miller's (2010) ranking scorecard and assigned a score of 68, 66 and 48 respectively. The results showed that Region I and II have better chances of finding shale gas. Finally an assessment was made to quantify the volumes of oil and gas in-place using Comer's (2005) Hydrogen mass balance method. The estimated volumes were 36 billion barrels of original oil in-place and 44.5 trillion cubic feet of original gas in-place in comparison to 119 billion barrels of original oil in-place and 230 trillion cubic feet of gas in-place in the Woodford for the entire Permian Basin (Texas & New Mexico). The assessment confirms that Woodford shale is a major unconventional source of both oil & gas in New Mexico.
Analyzing Wellbore Temperature Distributions Using Nonisothermal Multiphase Flow Simulation
Authors: Wang Zhe , Horne Roland N.
Published: May 2011

The need to interpret wellbore temperature profiles measured by Distributed Temperature Sensors (DTS) requires a correspondingly sophisticated type of well model. To be specific, this well model should be capable of predicting pressure and temperature distributions under a nonisothermal, multicomponent and multiphase production scenario. This paper describes the procedure of building a numerical well model, in which wellbore pressure and temperature were solved separately and then coupled by iteration. Accuracy was assured by the following three ways: 1. Using drift flux model to predict multiphase flow pressure; 2. Fluid PVT properties were obtained by solving Equations of State, which is more accurate than the values obtained by averaging or mixing rules; 3. Using numerical methods to solve the heat transfer between wellbore and formation, avoiding the assumption of an invariant relaxation length. This model was verified by comparing with several other models. Finally, based on this well model, several phenomena (e.g. multiphase flow, Joule-Thomson effect) affecting the pressure and temperature distribution were studied and their influences were evaluated. This study concluded that a rigorous and complete well model is important for accurate prediction of the temperature profile under complicated flow scenarios. This work allows flowrate profiling based on DTS data. The understanding of how different phenomena influence the temperature distribution is helpful to understand downhole production scenarios.
Improving Characterization and History Matching Using Entropy Weighted Ensemble Kalman Filter for Non-Gaussian Distributions
Authors: Nejadi Siavash , Trivedi Japan J , Leung Juliana
Published: May 2011

The Ensemble Kalman Filter (EnKF) has gained popularity over recent years as a Monte-Carlo based technique for assisted history matching and real time updating of reservoir models. The EnKF procedure utilizes an ensemble of model states (e.g. realizations of reservoir properties such as porosity and permeability) to approximate the covariance matrices used in the updating process. EnKF works efficiently with Gaussian variables and linear dynamics, but it often fails to preserve the reference probability distribution of the model parameters and to achieve an acceptable production data match where the system dynamics are strongly nonlinear, especially of the type related to multiphase flow, or if non-Gaussian prior models are used.

In order to alleviate these drawbacks, we investigated various weighted averaging techniques for computing the ensemble mean by introducing a weighting factor to each ensemble; two new formulations were implemented. The first weighting factor was calculated based on the mismatch in entropy of the model parameters, a normalized measure of the spread of a given probability distribution. The second weighting factor was computed using the forecast mismatch. In addition, both weights could be applied at a single updating step for reducing the forecast mismatch and maintaining the prior distribution simultaneously.

The performance of traditional EnKF and these weighted EnKF methods were evaluated by performing various simulation studies with different reservoir heterogeneity. The qualities of the final matching results were assessed by computing the experimental histogram and variograms of the final ensemble, as well as the Root Mean Square Error (RMSE) of the predicted data mismatch.

The results reveal that reasonable improvement in the efficiency of the EnKF is achieved by suggested weighted techniques. The RMSE of the predicted data is improved, and the quantity of spurious model parameters is reduced at each updating step. Taking advantage of the entropy based weighting factor assists the filter to preserve the reference distribution. The improvement indicates that the Entropy weighted EnKF (EWEnKF) has a significant potential to resolve the shortfall of traditional EnKF in reservoir characterization and history matching of challenging reservoirs with non-Gaussian distributions.
Reservoir Management Using Streamline-Based Flood Efficiency Maps and Application to Rate Optimization
Authors: Park Han-Young , Datta-Gupta Akhil
Published: May 2011

3-D streamlines provide an effective tool for reservoir management because of their ability to display reservoir flow and well connections in a physically intuitive manner. Streamlines have been extensively used to investigate the interaction between heterogeneity and well patterns and also for rate allocation and pattern balancing. More recently, streamlines have been used in conjunction with constrained optimization techniques for improving waterflood performance via rate control. Field scale rate optimization problems, however, involve highly complex reservoir models, production and facilities constraints and a large number of unknowns, making them inaccessible for routine waterflood management.

In this paper we provide a simple and easy to use workflow for waterflood rate optimization using streamline-based flood efficiency maps that display the flux and time of flight distribution amongst producing wells. We demonstrate the use of flood efficiency map to optimize the injection/production rates to maximize waterflood sweep efficiency by equalizing the average time of flight (TOF) amongst the producing wells in regional basis. Our optimization approach is extremely efficient because it relies on simple analytic calculations to compute weighting factors for injection and production rates to minimize the TOF variance amongst producing wells. Because the approach does not rely on formal and complex optimization tools, it is particularly well-suited for large-scale field application. Also, the approach can be used with both streamline and finite difference simulators. For finite-difference simulations, the streamlines and time of flight are derived from the flux field generated by the simulator. Multiple examples are presented to support the robustness and efficiency of the proposed waterflood management scheme. These include 2D synthetic examples for validation and a 3D field application.
Simulation Study of 2-D SAGD Experiment and Sensitivity Analysis of Laboratory Parameters
Authors: Ashrafi Mohammad , Souraki Yaser , Karimaie Hassan , Torsaeter Ole , Kleppe Jon
Published: May 2011

Bitumen resources constitute a high portion of the total world oil resources. The main recovery mechanism for these high viscous fluids is to reduce their viscosity by the application of heat, mostly by introducing steam.

Among different steam injection schemes, steam assisted gravity drainage (SAGD) has become the method of choice applicable to bitumen and oil sand reservoirs. In these extra heavy oil reservoirs the reservoir has almost no injectivity due to high oil viscosity, and therefore conventional steam flooding is hard to conduct. SAGD, however, reduces the viscosity of bitumen in place and the heated bitumen drains due to gravity forces towards the production well and is then being produced.

Our simulation study is based on the experimental work done by Chung (1988) and the simulation model of this experiment by Chow (1993). Chung's physical experiment was a 2-D model to simulate SAGD experiment in laboratory.

A reservoir simulation model was built using a numerical thermal reservoir simulator. The model was then tested and validated with Chung's physical model. Having a valid model, sensitivity analysis was run to examine the effect of different simulation parameters on recovery and steam oil ratio.

The sensitivity parameters tested are steam temperature and quality, the permeability of the model, both horizontal and vertical, different well placement schemes, and the effect of grid refinement. High permeability was found to have a profound effect on recovery.

Different steam temperatures and qualities were examined. The best injection condition was found to be 130 °C and 90% quality, beyond which no increased recovery was achieved.

Different injector and producer placements were tested. Placing injector and producer diagonally in the model showed the best horizontal sweep efficiency in the laboratory model.

The Chung's experiment was done with Cold Lake crude oil. Our model was tested using bitumen with higher viscosity from Athabasca and results showed that in order to get the same recovery as in the Cold Lake case; the temperature must be increased to 140 °C as compared to 100 °C for the case with lower viscosity oil.
Petrophysics of Triple Porosity Tight Gas Reservoirs with a Link to Gas Productivity
Authors: Deng Hui , Leguizamon Javier , Aguilera Roberto
Published: May 2011

Petrographie work on thin sections from rock samples collected in tight gas sandstones of the Western Canada Sedimentary basin (WCSB) shows that the sandstones are composed of intergranular, microfracture + slot, and isolated non-effective porosities. The petrographic observations of these triple porosity rocks have led to a petrophysical interpretation with the use of a triple porosity model.

Tight gas reservoirs are very complex heterogeneous systems that have been evaluated in the past mostly with single porosity models. We propose that these types of reservoirs can be better represented by triple-porosity models for more rigorous quantitative petrophysical characterization. The triple porosity model discussed in this paper fits very well the petrographic observations leading to a more rigorous characterization of effective and non-effective porosity.

The petrography and core-calibrated triple porosity model is then used for well log interpretation of those wells where these data are not available. The result is a reasonable quantitative characterization of the tight gas reservoir that can be used for improving hydraulic fracturing design, flow units determination, reservoir engineering and simulation studies. The data can be determined at room conditions and simulated conditions of net stress.

It is concluded that honoring with a triple porosity model the different types of porosities observed in thin sections and cores lead to more rigorous and useful petrophysical interpretations that can be linked to gas productivity.
Acoustic Wave Testing System for Monitoring the Vapor Chamber in Vapor Extraction Process
Authors: Zhou W. , Paranjape R. , Asghari K.
Published: May 2011

The acoustic wave detection system is considered a non-destructive monitoring system to estimate distances using measurement of the time-of-flight of an ultrasonic wave. In this paper, a comprehensive experimental study was conducted to investigate the feasibility of the acoustic wave detection system in monitoring the shape and position of the gas phase in the vapor extraction process. For this purpose, various stages of vapor chamber evolution in the Vapex process were experimentally simulated by changing the shape of air balloons buried in simulated porous media in a lab scale model. Then, an array of ultrasound transducers and receivers were used to measure time-of-flights at different stages of the vapor chamber growth. Finally, the collected data were fed into a signal processing program developed in this study to determine the shape of the vapor chamber. Conducted analysis in this study include: sound speed testing in different porous media, signal attenuation tests in different porous media, imaging of different simulated vapor chambers in different porous media, and the acquisition and analysis experiments. Results show that acoustic wave detection can be used for accurate mapping of the position and shape of the vapor chamber in the studied process. Monitoring the shape and growth of the vapor chamber provides valuable information for optimizing oil production in order to maximize oil recovery. This is the first attempt at using acoustic wave detection techniques in monitoring the phase movement in the Vapex process. Results of this study show that this technique can be potentially used for this purpose.
Efficiency of Oil Recovery by Low Salinity Water Flooding in Sandstone Reservoirs
Authors: Nasralla Ramez A. , Alotaibi Mohammed B. , Nasr-El-Din Hisham A.
Published: May 2011

Low salinity water is a promising technique for improving oil recovery in sandstone reservoirs. However, the optimum conditions that improve oil recovery by low salinity flooding are uncertain due to the lack of understanding of fluid-rock interaction mechanisms. In this study, several coreflood experiments were conducted to explain the mechanisms involved when recovering oil with low salinity water.

Core flood experiments were run to determine the effect of water salinity on oil recovery in the secondary and tertiary modes. Deionized water and three different brines (from 5,000 to 174,000 mg/l) were tested; these brines represent a Middle East field case. Two different types of crude oils were used to investigate the effect of oil composition on the applicability of low salinity water flooding. All experiments were conducted on 5 to 6 in. long outcrop Berea sandstone cores. Core flood effluent was sampled regularly to follow rock-fluid interactions, and it was achieved by measuring the concentration of different cations.

Core flood tests indicated that injection of deionized water in the secondary mode resulted in a significant improvement in oil recovery, up to 22%, compared to seawater. However, no additional oil was recovered in the tertiary mode. This paper contributes to the understanding of cation exchange caused by low salinity water injection, and how this exchange alters the wettability of the rock and reduces the electrostatic attraction forces between oil and rock. Likewise, we discuss formation damage that might occur during low salinity waterflooding in Berea sandstone, and investigate the contribution of formation damage to oil recovery improvement.
Residual Trapping in Simultaneous Injection of CO2 and Brine in Saline Aquifers
Authors: Javaheri Mohammad , Jessen Kristian
Published: May 2011

Disposal of carbon dioxide (CO2) into saline aquifers appears to be one of the best CO2 sequestration options in terms of capacity and technology. Injected CO2 migrates invariably upwards due to buoyancy forces. In most common aquifer settings, the density difference between CO2 and brine is sufficiently high that gravity force is a pre-dominant factor that controls the upward migration of a CO2 plume. Any scheme that can retard the vertical movement of the plume can enhance the entrapment of the injected CO2 and reduce the risk of potential leakage back into the atmosphere.

An appealing scheme for sequestration projects in aquifers involves simultaneous injection of brine and CO2 from vertical wells, where brine is injected in the upper part of injection well(s) and CO2 is injected in the lower portion of the well(s). This scheme inhibits the rapid upward migration of CO2, since the injected CO2 is forced to move horizontally during the injection period. The horizontal displacement increases the volume of the aquifer that is contacted by the injected CO2, and hence, the residual entrapment of the CO2-rich phase can be increased significantly. The upward migration of CO2 away from the injector occurs predominantly in a counter-current flow mode.

In this study, we compare residual entrapment of CO2 for the simultaneous injection of CO2 and brine in four different aquifer settings. The four aquifer settings are selected from the classification scheme proposed by Kopp et al. (2009). It is shown that for large gravity numbers, there is a significant difference between the four aquifer settings in terms of storage capacity with warm aquifers having the least storage capacity and cold aquifers providing the largest storage capacity. The distance at which segregation of brine and CO2 is complete, not only depends on the gravity number, but also on the aquifer setting. It is indicated that residual entrapment of CO2 depends on brine injection rate and higher rates of brine (lower gravity number) increase the fraction of CO2 that is trapped in a residual phase. Finally, we demonstrate that the reduction in the relative permeability of both phases, due to counter-current flow, has a major impact on the sweep efficiency of the injected CO2 and hence impact both the distance traveled before full segregation and the level of residual entrapment.
Tapered-Bean Steam Chokes Revisited
Authors: Castrup Suzanne , Latif Faisal , Kalbani Ali Al
Published: May 2011

Controlling and monitoring flow rates at continuous and cyclic steam injection wells are important elements of reservoir heat management. For nearly 30 years, critical flow chokes have proven to be the most reliable and cost-effective means of controlling steam injection into heavy oil reservoirs. Flow control efficiency has been further improved with tapered-bore bean inserts to achieve critical flow with only 10% to 15% pressure loss across the choke.

For the past 10 years, the standard steam choke assembly has consisted of a 1-inch outer diameter (O.D.) by 6-inch long bean with 6° tapered-bore inserted in a 2-inch O.D. cage nipple or housing. Larger diameter cage nipples and bean inserts have been required for steam injection rates exceeding 500 b/d. More recently, a cost-cutting practice has been employed using shorter tapered-beans inserted in standard choke assemblies.

This paper presents the results of field tests conducted to evaluate the effectiveness of shorter tapered-bean length for controlling steam injection rates. Transition from subcritical to critical flow and overall pressure loss for different tapered-bean lengths are presented. A modified Thornhill-Craver flow rate equation is provided for critical and subcritical flow regions. Calculated and measured rates are compared and their relative uncertainties are assessed.
Geochemical Allocation of Commingled Oil Production or Commingled Gas Production
Authors: McCaffrey Mark A. , Ohms Danielle H. , Werner Michael , Stone Christopher , Baskin David K. , Patterson Brooks A.
Published: May 2011

We have made substantial improvements to the previously published methods for geochemical allocation of commingled oil production and/or commingled gas production. This new method has allowed allocation of commingled production from wells at less than 2–5% of the cost of production logging. Four case studies are shown here. In the first two studies, commingling of the wells was subject to approval of the Alaska Oil and Gas Conservation Commission (AOGCC). Before agreeing to the use of geochemical allocation, the AOGCC required the well operator to perform multi-month trial studies in which the wells were monitored both by geochemical allocation and by production logging. The individuals performing the geochemical allocation were kept blind from the results of the production logging until the studies were completed. Close agreement between the geochemistry-based allocation values and the production-logging-based allocation values resulted in AOGCC approval of continued use of the geochemical method for oil production monitoring of these two wells. Two additional case studies presented here illustrate how geochemical allocation can be used to monitor the effects on production of (1) changes in water injection into nearby wells, and (2) closing or opening perforations within a well.
Palliative Care: A Place for Caregivers to Thrive
Authors: Breiddal Susan Mary Fownes
Published: May 2011

The author proposes that rather than being an inherently stressful environment the palliative care setting has the potential to provide caregivers practice in being connected. When the setting is viewed in a non-judgmental way, then events can be seen as stimuli for reactions, and self-care moves from external solutions to internal shifts. By examining the widely held belief that the palliative care environment is necessarily challenging, the author presents the possibility of an alternate explanation for why caregivers might experience stress, proposing three resources that illustrate mindfulness practice, reflexivity, and self-awareness. These strategies might help caregivers cultivate a sense of empowerment and growth, while at the same time assisting them to better care for their clients. She concludes that when self-care is a way of being rather than doing, the environment becomes one where growth is possible and palliative care-giving and receiving become one.