bluuebunny/crossref_metadata_2025 huggingface dataset:
Improved Analytical Solution for Real Gas Flow in Porous Media
Authors: Chien Tony , Caudle S. H.
Published: December 2007

The real gas potential function presently being used in the oil and gas industry does not yield valid solutions when the reservoir pressure falls substantially below the initial value. To tackle this problem, a new real gas potential has been implemented. The effects of pressure-dependent fluid and rock properties such as gas viscosity, compressibility, porosity and permeability have been considered. Advanced mathematical derivations with respect to nonconstant hydraulic diffusivity have been performed, and an analytical solution has been obtained. Solutions for multiple-rate and multiple-well systems as well as bounded reservoirs of any shape have been successfully developed by using the principle of superposition and an unsteady-state bounding technique. Validation of the analytical solution has been favorably achieved by comparison with a finite-difference simulation. Reservoir pressures and flowing bottomhole pressures in gas wells calculated by the analytical solution presented in this paper are more accurate than by other analytical methods previously available in the literature.
Original Gas in Place and Decline Curves from Early Stabilized Rate-Time Data
Authors: Keating J. F. , Chen H. Y. , Wattenbarger R. A.
Published: December 2007

With the method presented in this paper, early rate-time data can be extrapolated to estimate original gas in place (OGIP) and a future decline curve. The advantages of this new method are: (1) OGIP can be determined as early as possible without shutting in the well, (2) a future decline curve for a constant flowing bottom hole pressure can be calculated and (3) the only data needed are rate-time data, an estimate of the initial reservoir pressure, and an estimate of the constant flowing bottom hole pressure. The disadvantage of this method is that it assumes stabilized flow for the future decline curve. Verification of the method was obtained by comparing results with one field case and 16 simulator cases.
CO2 Operating Plan, South Welch Unit, Dawson County, Texas
Authors: Hill W. J. , Tinney T. J. , Young L. C. , Stark K. L.
Published: December 2007

The South Welch Unit of the Welch Field commenced full scale injection of CO2 beginning in September of 1993. The flood design was based on the performance of a 180 acre pilot conducted from 1982 to 1987. A compositional model study of the pilot performance was used to design a CO2processing facility and the full scale flood operating approach. Primary, secondary and tertiary performance matching were used to verify the reservoir and process description and to forecast performance under a full field scenario. Scaleup was based on floodable pay from the modeled area related to the remaining areas under consideration for flood.

Reservoir simulation and economic analysis were used to investigate water alternating gas (WAG) cycle lengths, WAG ratio, and total slug sizes. Phasing of areas was coupled to level plant loading considerations, water handling limits, and short term profitability to develop an operating plan for the Unit.
A Proven Methodology for Comparison of Cement Acid Solubility
Authors: Carpenter R. B. , Edwards T. M.
Published: December 2007

While there have been several good papers that describe the dissolution of Portland cement by hydrochloric:hydrofluoric acid (HC1:HF) solutions, no one has established a detailed comparative test procedure.1-3 The absence of a single, specific methodology left all parties to form their own interpretations of the acid solubility test described briefly in SPE 18986.

Discrepancies between the various procedures produced inconsistent results. Some laboratories were keeping the heated acid in glass vessels for extended periods before the cement specimen was introduced. Using glass vessels allows the HF to spend on the glass instead of the cement. Others were using grease on the curing molds and testing the cubes without adequate grease removal; this limits cement/acid contact. Different methods for agitating the acid and suspending the cement cubes in the acid were also being employed. One company was desiccating the specimens before acid immersion; another was using a complete inhibitor and surfactant package. Even the concentration and volume of acid was not universally agreed upon. All these factors must be controlled for an accurate comparison of data between different laboratories

Representatives from two operating companies have developed a jointly endorsed and very explicit methodology for conducting cement acid solubility tests. Equipment, chemicals, preparation methods and report forms were specified in extreme detail. This procedure was designed to address the above mentioned problems and yet be cost effective and applicable in any field lab.

Although the new test remains qualitative, it has provided consistent comparisons of conventional and microfine Portland cements. A quantitative method would require more costly, specialized equipment and limit field application.

This procedure provides a sound method for evaluating the relative acid solubility rates of various cement blends. It can also be used as a tool for developing improved cement designs or quality control procedures.
Integrated Recovery Efficiency Forecast Models for San Andres Reservoirs of Central Basin Platform and Northern Shelf, West Texas
Authors: Shao Hongbin , Brimhall R. M. , Ahr W. M. , Wu C. H.
Published: December 2007

This paper presents integrated recovery efficiency forecast models of primary, initial waterflood and infill drilling for San Andres reservoirs in the Central Basin Platform and the Northern Shelf, West Texas. We develop the integrated forecast models using a depositional energy index, a porosity index and a well spacing index. The depositional energy index is developed based on the idealized depositional sequences of the ramp and the shelf model. Normalization is used to define the porosity index and the well spacing index. A linear regression analysis is conducted on a data base to develop the integrated forecast models.
Use of Hydraulic Interwell Connectivity Concepts in Reservoir Characterization
Authors: Canas J. A. , Malik Z. A. , Wu C. H.
Published: December 2007

This paper presents the use of hydraulic interwell connectivity concepts to characterize the reservoir for waterflood performance evaluation. These hydraulic interwell connectivity concepts are presented in terms of two indices: The Interwell Flow Capacity Index (IFCI) and the Hydraulic Interwell Connectivity Index (HICI). This approach utilizes the reservoir flow capacity and production/injection performance data to calculate the IFCI and HICI. The spatial distribution and correlations of these indices are useful to evaluate the reservoir characteristics for waterflood design and performance analysis. A Colombian (South America) sandstone reservoir in La Cira Field is used to illustrate the application of these concepts.
In Conflict: Marginal Reserves vs. Enforced Abandonment
Authors: Haynes C. D.
Published: December 2007

The United States has become a nation of marginal oil and gas wells. Well abandonments have become commonplace, and each decline cycle in the price of oil and gas brings on a new round of well abandonments. Yet, we know that the majority of oil and gas resources in developed areas are still in the reservoirs. The plugging and abandonment (P&A) of oil and gas wells because of economic conditions is a byproduct of our market economy, and is a "fact of life" in our business. Typically, a well is abandoned because it has fallen below its economic limit, an arbitrary production rate depending, in part, on the present price of oil and gas.

Economic forces are not alone in dictating well abandonment. The timely abandonment of wells is prompted by state regulatory agencies, who must rigidly enforce abandonment statutes for environmental and bonding reasons.

The dilemma brought on by P&A is the damage usually done to the well which precludes inexpensive future access to the reservoir. This is mainly because of damage resulting from the salvaging of casing strings in the well at the time of abandonment. Most oil and gas producing states either allow or even require the recovery of casing during well abandonment. While of questionable economic value, this procedure is commonplace and virtually eliminates future reentry into the wellbore.

This paper discusses the rationale and economic considerations inherent in the P&A process. It suggests a means for regulating the abandonment of oil and gas wells without removing casing strings, while satisfying concerns of environmental damage downhole.
A Semi-Analytical Solution to Three-Dimensional Hydraulic Fracture Propagation in Multistress Media
Authors: Rueda J. I. , Rahim Zillur , Holditch S. A.
Published: December 2007

abstract

Hydraulic fracturing plays a very important role in the enhancement of gas and oil production rates from low permeability reservoirs. To mathematically model a hydraulically induced fracture, one must couple equations describing formation elasticity, fracture fluid flow, and fracture mechanics. Also, the effects of fluid leakoff into the poro-elastic formation must be considered in association with the fracture fluid mass conservation equation. Fracture propagation models in multilayer systems are needed to better understand hydraulic fracturing and to optimize a fracture treatment design.

Currently, the determination of the optimum fracture treatment in formations of three or more layers are being carried out using pseudo three-dimensional or full three-dimensional fracture propagation models. Pseudo three-dimensional models usually run rapidly on personal computers. However, pseudo three-dimensional models are mainly applicable to fractures where the total fracture length is several times greater than the fracture height. If fracture height growth is a problem, full 3-D models are required to solve the fracture propagation problem rigorously. However, these sophisticated 3-D models require considerable computer memory, run time, and expertise by the user. Saving CPU time is very important in the optimization of the fracture design process because numerous fracture predictions and sensitivity analyses are needed to determine the optimum fracture design.

The objectives of this paper are (1) to develop an efficient three-dimensional, semi-analytical fracture propagation model that can be used to predict the created fracture dimensions and pressure inside the fracture for a given injected volume in a multilayer reservoir, and achieve results more compatible with a full 3-D model, and (2) to develop an accurate 3-D model that is easy to run and can execute rapidly on a personal computer.

In this research, We have developed a full 3-D fracture propagation model that allows us to compute efficiently the fluid pressures and fracture dimensions in a multilayer medium with asymmetric characteristics in each layer of rock. This model considers two-dimensional fluid flow inside the fracture and computes pressure drop in both directions of the fracture height and fracture length. We have used cubic polynomial approximations to represent both the fluid pressure and the in-situ stress profiles. Thus, we could use the analytical solution to determine displacements of an elliptical crack under arbitrary normal loading presented by Shah and Kobayashi1 (SK). We use the first variational technique to approximate certain partial differential equations. These equations are coupled with the analytical solution presented by SK1. As such, asymmetric fracture growth can be solved for a multilayer system, where each layer can have unique mechanical properties such Poisson's ratio, in-situ stress, Young's modulus, and fracture toughness.
A New Iterative Mathematical Model for the Analysis of Imbibition Carbonated Waterflood in Naturally Fractured Reservoirs
Authors: Shenawi S. H. , Wu C. H. , Jiang Chunhuan , Luan Z. A.
Published: December 2007

A new semi-analytical mathematical model (IMOD) is developed as a part of a multidisciplinary study1-5 to investigate the potential of imbibition carbonated waterflood in low-permeability, naturally-fractured reservoirs. The model is based upon the concept of Buckley-Leverett type flow6,7 in a fracture surrounded by matrix blocks. The rate of water imbibition with varying water saturation at the imbibition boundary is represented by a convolution integral. The numerical iteration technique determines the fracture and matrix water saturation distributions in Laplace space. Stehfest's numerical Laplace inversion algorithm7 inverts the solutions to real domain.

Laboratory flow test data2,4 are used to check the validity of IMOD. Core face flushing technique is used in the imbibition experiments conducted on chalk cores. The test temperatures are 70 °F, 110 °F, and 150 °F. Concentrations of carbonated water solutions are 0.0, 2.3, 4.0 and 5.5 percent by weight of CO2, respectively.

The significant achievements of IMOD are: (1) it can provide the nonlinear solutions for a range of oil to water viscosity ratios and (2) the same model can be used for both plain and carbonated water imbibition recovery by adjusting the maximum recoverable oil (R∞) and imbibition recovery constant (λ). Results of the analysis show that: (1) the computed oil recoveries match the laboratory performance very well; (2) the computed oil recovery and phase saturation distribution in the fracture and matrix are greatly influenced by the magnitude of viscosity ratio; and (3) the imbibition recovery constant λ has a significant effect on the rate of imbibition oil recovery, thus, must be checked with laboratory data before modeling the reservoir performance.
Case History Analysis: Materials for Completion Equipment in CO2 Service
Authors: Chitwood G. B. , Coyle W. R. , Hilts R. L.
Published: December 2007

This paper presents two case histories from oil wells in the Middle East in which hardened and tempered alloy steel completion equipment underwent severe corrosion from CO2. The fact that in one case the API J-55 tubing string did not exhibit corrosion but did in another case indicates that corrosion in CO2 service can be influenced by several factors: the steel composition, its strength, or its heat treatment. A study was initiated to determine which properties or combination of properties should be altered to remedy the problem. Consideration was given to the use of different steels and/or heat treatments for completion equipment in order to achieve corrosion performance in CO2 environments similar to that of J-55 tubing.

It was determined that the alloy steel normally used for this equipment could not be reprocessed with heat treating to provide the needed corrosion resistance without a compromise of its metallurgical properties. This indicated a need to investigate alternative materials. The subsequent investigation of 9Cr-1Mo and 410 stainless steels found them to have superior corrosion resistance and good metallurgical properties. Therefore, these will be the materials of choice for completion equipment used to replace existing alloy steel equipment in these wells.
Miscible Displacement in Fractured Porous Media: Part I—Experiments
Authors: Firoozabadi Abbas , Markeset T. I.
Published: December 2007

Miscible displacement experiments were carried out in a number of matrix/fracture configurations. In all the experiments, fracture aperture was more than 150 microns, which exceeds field scale fracture thickness. Even with high fracture aperture, the miscible displacement process is shown to be very efficient. The injected fluid breaks through fast, but the injected solvent effluent concentration increases very slowly to about 1 PV injection. The results reveal that miscible displacement in fractured porous media can be a very efficient process.
A New Microbial Technology for Enhanced Oil Recovery and Sulfide Prevention and Reduction
Authors: Hitzman D. O. , Sperl G. T.
Published: December 2007

A new technology based on the existence and microbial utilization of the preformed volatile fatty acid content of the reservoir waters, prevents sulfate reduction by sulfate reducing bacteria by the competitive removal of the volatile fatty acids in the reservoir waters. A new microbial population is developed in the presence of nitrate which has the capabilities of producing in-situ products such as gases and polymers — all known recovery agents. Laboratory investigations demonstrate the versatility and potential of the system to alter microbial populations by subtle changes in the reservoir waters. Core flooding data show increased oil production. This novel approach to prevent and reduce sulfide while at the same time to increase oil recovery is termed "Biocompetitive Exclusion". A microbial liability in the field is turned to an advantage and offers the petroleum industry a low cost methodology for reservoir control and stimulation.
Rangely Weber Sand Unit CO2 Project Update: Decisions and Issues Facing a Maturing EOR Project
Authors: Masoner L. O. , Wackowski R. K.
Published: December 2007

The Rangely Weber Sand Unit (RWSU) CՕշ Project is juggling its maturing recovery performance against continued flat oil prices. The Unit's business goals of reducing operating cost per barrel of OEG production and maximizing net present value require improving the process efficiency. The recovery efficiency for the project initially improved, but has recently begun to decline as the CՕշ process matures. Achieving the business goals calls for identifying the key issues and decisions. Accomplishing this entails linking the recovery process and the business value measures. For this maturing CՕշ flood, the results indicate that the sweep efficiency defines the key decisions. Decisions that improve the sweep efficiency include water-alternating-gas management, workovers, pattern alignment, injected fluid apportionment, and field contraction.
Data Acquisition Design and Implementation: Opportunities and Challenges for Effective Programs in Mature Reservoirs
Authors: Pande P. K. , Clark M. B. , Blasingame T. A. , Doublet L.
Published: December 2007

Data acquisition design and implementation challenges for mature reservoirs which are targets for Improved Oil Recovery (IOR) applications are discussed in this paper. Examples are provided for Shallow Shelf Carbonate (SSC) reservoirs in the Permian Basin of West Texas.

What Are Mature Reservoirs?

Mature reservoirs are defined as properties with additional recovery potential by implementation of advanced reservoir characterization tools and techniques, reservoir management and/or changes in recovery mechanisms. Attributes of mature reservoirs are depicted in Figure 1, which shows the importance of reservoir characterization as a function of field development stage. Reservoir characterization and an understanding of heterogeneity become more important for maturing reservoirs as these factors have a profound impact on future reservoir development and management strategies. Mature reservoirs are typically characterized by some type of secondary drive mechanism. A change to a tertiary mode or implementation of other IOR methods may be necessary to extend the economic limit and productive life of the field.

In recently discovered reservoirs, advances in reservoir management technologies and practices allow operators the opportunity to implement timely, judicious and integrated data acquisition programs (Ref. 1–3). Typically, data acquisition focuses on use of a team approach (Ref. 4, 5) as illustrated in Figure 2.

A team approach is also important to achieve data acquisition objectives in mature reservoirs. However, the data acquisition situation may be very different from that of "new" reservoirs. The desire and need for IOR may be critical as the economic limit may be rapidly approaching and data required for IOR may not be available. Smaller reservoir size and lower remaining reserves may present economic constraints towards the acquisition of essential data for the implementation of many IOR methods. The lack of production, fluid properties and other data in the earlier stages of field development may present uncertainties in history matching with numerical simulation methods. This results in unreliable reservoir performance forecasts for IOR. Often, the implementation of data acquisition programs in mature reservoirs present opportunities to enhance near-term reservoir performance through effective reservoir management.

Data acquisition strategies for properties which are being considered for abandonment are not addressed in this paper. Redevelopment of these properties is often required to exploit behind pipe potential and undeveloped zones or horizons.
A Methodology for Prediction of Oil Recovery by Infill Drilling
Authors: Biglarbigi Khosrow , Paul G. W. , Ray R. M.
Published: December 2007

The U.S. Department of Energy (DOE) through Scientific Software-Intercomp (SSI) has developed a predictive model to estimate potential incremental reserves by infill drilling. The Infill Drilling Predictive Model (IDPM) is a three-dimensional (stratified), two-phase (water and oil) model which uses a streamtube simulation approach in calculating incremental recovery by infill drilling from 5-spot waterflood to either 5-spot or 9-spot infill patterns. The IDPM framework is similar to the enhanced oil recovery (EOR) predictive models developed by the National Petroleum Council (NPC) for its 1984 study of U.S. EOR potential. The IDPM has been successfully validated by SSI and independently by the authors using BOAST-II, a three-dimensional, three-phase black oil simulator. Using the IDPM, however, requires knowledge of two important heterogeneity elements which are not easily or often measured in the field. These heterogeneity elements are: (1) pay continuity, and (2) permeability variation among layers.

This paper presents a methodology to approximate pay continuity and permeability variations among layers using the history match of production data. This methodology will facilitate the use of the IDPM in evaluating infill drilling potential in existing waterflood fields. The methodology has been validated against nine actual field case histories.
A Probabilistic Forecasting Method for the Huntley CO2 Projects
Authors: McNutt P. B. , Pittaway K. R. , Rosato R. J. , Beamer R. E.
Published: December 2007

Two words describe our past approach to miscible CO2 economic forecasting: deterministic and optimistic. In order to assess the Huntley CO2 projects more probabilistically and realistically, a team was formed. The team identified five primary areas of risk that are specific to CO2 projects. The team used judgement, experience, and historic information to assign probability distributions to these areas. Monte Carlo simulation was then used to calculate the distribution of economic outcomes. The mean values of the resulting economic indicators were 20% to 36% below the previously calculated deterministic solutions. This paper describes the method that the team developed, the distributions that were used, what risks were excluded and why, and the resources that were used.
Reservoir Management in the Duri Steamflood
Authors: Gael B. T. , Putro E. S. , Masykur Akmal , Lederhos L. J.
Published: December 2007

The Duri Steam Flood (DSF) project has 12 development "Areas" to be processed from now until the year 2021. DSF's development plan uses the following strategies for steam scheduling and reservoir management: inject all patterns and pay intervals evenly at 1.2 BCWEPD/NAF* until steam breakthrough occurs in multiple wells in a pattern, then shift steam out of the breakthrough zones and into the non-breakthrough zones by workovers and adjustments to string injection rates, and finally, after injecting about 1 pore volume steam, reduce rates to heat balance (Vogel1) levels so that by ten years of injection most of the steam capacity can be moved to a new Area. Throughout the project life, producer backpressures are kept as low as feasible. These strategies maximize NPV for the whole project.

Reservoir management in DSF is a life-cycle concept which starts at initial planning/designing of an Area and ends with its abandonment. There are four stages of management for each Area: 1) design and construction, 2) steam ramp-up, 3) a main stage where oil production peaks then progresses to steam breakthrough and requires focus on pattern/layer steam rate optimization and steam rate reduction, and 4) an end-of-project stage where depletion operations are undertaken with due attention given to prevention of inter-Area interference. Reservoir management practices are substantially different depending upon which stage an Area is in.
Injectivity of Sulfonated Polymers Under North Sea Field Conditions
Authors: Noik Christine , Audibert Annie , Delaplace Phillipe
Published: December 2007

Oil field operations for polymer flooding under drastic conditions need suitable commercial products. This study focusses on the flow behavior of suifonated polyacrylamides specially designed to be used under high temperature conditions. The experiments were performed under North sea conditions, i.e. temperature 90°C, seawater brine and North Sea field cores. The main consequences of the introduction of sulfonate units in a polyacrylamide chain are the improvement of thermal stability and shear resistance and a low level of adsorption, with no major problem of retention during core flow.
Closing the Lab-Field Gap: A Look at Near-Wellbore Flow Regimes and Performance of 57 Field Projects
Authors: Smith J. E.
Published: December 2007

The goal of this paper is to link lab and field data in order to resolve a paradox that has caused the shelving of many worthwhile improved oil recovery field projects. Theoretical shear rate calculations often show that polymer or colloidal dispersion gels injected in unfractured reservoirs through perforated completions face certain destruction in terms of shear degradation. Under these conditions, calculated shear rates are often extremely high, and tend to suggest there is no point in injecting polymer, as it will be destroyed to the point of ineffectiveness.

The lab-field paradox is that polymer and colloidal dispersion gels have been injected into these types of reservoirs numerous times and have proven highly successful in spite of high shear rate calculations that suggest otherwise. This paradox represents an important discrepancy between lab/theory and actual field performance. In this paper, lab and field data were combined for 62 injection wells from 57 actual field projects that utilized polymer and in-depth gels. 89% of these projects were successful improved oil recovery floods, yet theoretical shear rates in excess of 50,000 s 1 were calculated for 42% of the injection wells, using basic field assumptions. Although lab data showed that polymer would be destroyed at these high shear rates, the polymer did perform in-situ in all of the injection wells.

Reasons for lab-field discrepancies are proposed and discussed. To determine which field assumptions have the strongest impact on calculated shear rates, sensitivity analyses were performed on several variables. Assumptions for apparent viscosity, injection flux area and permeability have the strongest impacts on results, and are the most poorly defined variables that go into the calculation. This work shows that shear rate calculations for field injection wells should be employed only with a strong knowledge of injection well completions and sensitivities on certain variables.
Improved Sweep Efficiency by Alcohol-Induced Salt Precipitation
Authors: Zhu Tao , Raible Clarence
Published: December 2007

A selective profile modification process was studied to improve volumetric sweep efficiency. This method involved adding alcohol to brine to reduce solubility of salt, which caused the salt to precipitate. For this process, a concentrated brine preflush was injected. This was followed by the injection of a water-soluble alcohol, such as ethanol.

The salt precipitation method has several potential advantages over other profile modification methods such as polymer gels. Profile modification by salt precipitation is not affected by adsorption, and other reservoir conditions, such as, fluid pH and temperature. These are conditions that may affect the gelation process and stability of polymer gels. For applications with CO2 floods, the solid salt is stable to subsequent CO2 flooding. Carbon dioxide flooding can lower the pH of reservoir fluids, a condition which may adversely affect the stability of some polymer gels.

Laboratory experiments indicated that the permeabilities of cores treated by salt precipitation were resistant to subsequent waterfloods with low-salinity brines. Core permeabilities recovered only 5 to 10% of the original permeability after injecting several pore volume of low-salinity brine. Also, corefloods demonstrated the feasibility of the new process to plug high-permeability regions. In parallel coreflooding experiments, the injection of alcohol and NaCl-saturated brine selectively reduced the permeability of highly watered-out cores. Using about 7% PV of reagent grade ethanol for salt precipitation, oil recovery with parallel corefloods of high and low permeabilities was increased by about 20% of the OOIP or about 60% above that of conventional waterflooding. For CO2 coreflooding experiments, the injection of ethanol and NaCl-saturated brine slugs resulted in 12% additional oil recovery of the OOIP or 45% higher oil recovery compared to that of CO2 floods without salt precipitation.
Transactional Environmental Assessments: Use in the Identification of Viable Enhanced Oil Recovery Projects
Authors: Wilson M. J. , Kiser S. C.
Published: December 2007

Environmental site assessments are a valuable tool in assessing the profitability of oil properties with enhanced oil recovery (EOR) opportunities. Industry and government should view the liabilities identified in the environmental site assessment process as research and development opportunities for product development and successful total resource management. The costs to permit, construct, and operate EOR projects within the framework of today's environmental regulations are quantifiable, predictable, and controllable to a certain degree. Knowledge of oil field operations and typical problem areas with the goal of total resource management evaluated in a creative way will help to extend the economic life of the EOR project.
CO2 Foam Field Verification Pilot Test at EVGSAU: Phase IIIA— Surfactant Performance Characterization and Quality Assurance
Authors: Tsau Jyun-Syung , Heller J. P. , Moradi-Araghi Ahmad , Zornes D. R. , Kuehne D. L.
Published: December 2007

This paper is a summary of both new and previous laboratory work done in support of the CO2-foam application in a pilot area of the East Vacuum Grayburg-San Andres Unit (EVGSAU) of southeastern New Mexico. This pilot test was a cooperative effort between the EVGSAU owners, New Mexico PRRC, and the Department of Energy. Different laboratory techniques used for the evaluation of CO2-foam mobility and surfactant adsorption on reservoir rocks are first discussed briefly. Recent results, that concentrate on work with the surfactant selected for use in this field pilot, are then presented. These results display CO2-foam mobility in EVGSAU core samples over wide ranges of surfactant concentration and core permeability. The results generally show a drastically decreased dependence on surfactant concentration above the critical micelle concentration (CMC), and a slightly favorable, but not prominent, dependence of mobility on rock permeability. A further rock sample characteristic pertaining to the initial conditions of the core-from "preserved" through various states of cleaning is also discussed. Additional discussion is given on surfactant adsorption, including results of measurements on Baker Dolomite as well as EVGSAU cores. Using refractometric analysis with the recirculation method, the adsorption results were found to be affected by the water salinity and core conditions. Quality control data for the bulk surfactant and injected solutions, and analyses of the produced brine for tracers and surfactant breakthrough are presented. Foam breakers and emulsion breakers were also evaluated for contingency use in case of the appearance of foam or emulsion in production facilities.
Performance of Morgan Pressure Cycling In-Situ Combustion Project
Authors: Marjerrison D. M. , Fassihi M. R.
Published: December 2007

Amoco Canada has been operating a pressure cycling fireflood at Morgan, in the Lloydminster area of Alberta, Canada, since the mid 1980's. A pressure cycle consists of air injection into a central injector accompanied by production from its surrounding producers. The reservoir contains a 12 API heavy crude and the wells are laid out in 30-acre (12 ha), 7-spot patterns. The rapid drop in the crude oil prices in 1986 led to the successful development and implementation of an innovative pressure cycling-combustion process. This paper looks at the performance of the project and the numerical modelling done to history match the results. The numerical modelling effort was undertaken to explain the high oil rates (individual wells at 120+ STB/D- 19m3/D) and the extraordinarily low injected air-to--produced oil ratio (AOR) of less than 2 MSCF/STB (355 m3/m3). Mechanisms incorporated in the numerical model include: (1) A high speed channel from the injector to the producer, (2) Combustion gas entrainment by the oil phase and (3) Oil upgrading. The physics involved with these mechanisms are explained and the model results are compared with the actual field data. Also, model sensitivities to variations in the assumptions regarding the mechanisms are discussed.
Water-Alternating-Steam Process (WASP) Alleviates Downdip Steam Migration in Cymric Field
Authors: Bautista L. S. , Friedmann Francois
Published: December 2007

The water-alternating-steam process (WASP) was implemented in a one-pattern field trial to control downdip steam breakthrough in a steeply dipping reservoir. The process was implemented because simulation studies of the trial area showed that WASP was technically and economically more effective than conventional rate reductions and foam diverters in correcting downdip steam breakthrough problems.

After two complete cycles, monitoring data was analyzed to determine the technical effectiveness of WASP in reducing reservoir temperatures and in maintaining both reservoir pressure and pattern production. In addition, the economic impact of WASP on thermal efficiency and economics was compared against predicted baseline performance.

Actual field results were also compared to performance predicted from simulation studies to evaluate the effectiveness of simulation in: (1) designing the initial cycle lengths and rates for the WASP field trial, and (2) qualitatively modeling the effect of WASP on the steam zone and project performance.
pH and Reaction Rate Changes During Single-Well Chemical Tracer Tests
Authors: Deans H. A. , Ghosh Rajat
Published: December 2007

The single-well chemical tracer (SWCT) method has been used to measure residual oil saturation to water flooding, (Sor)w, in more than 200 reservoirs since 1968. An essential step in the procedure is the hydrolysis of an ester, the primary tracer, in-situ. At the previous SPE/DOE Symposium4, the variation of hydrolysis rate with pH was claimed to cause serious errors in interpreted (Sor)w in certain cases. This effect has not been accounted for in SWCT test simulator programs, which are used to obtain (SOR)w by matching field measured tracer profiles.

The present work investigates the space-time variation of pH in the formation during a SWCT test. The method employed is simulation, using the chemical flood simulator program UTCHEM. The program was modified to account for the effects of ester hydrolysis reaction products on pH. The hydrolysis rate of ester, already present in the program was modified to depend on pH according to known reaction mechanisms.

UTCHEM was then used to simulate the SWCT test previously reported4 to be effected by pH variations. The shape of the predicted product tracer profiles is indeed changed by the variation of hydrolysis rate with pH. The new tracer profiles come closer to fitting the field-measured results, using a single-layer reversible-flow model. However, the interpreted value of (Sor)w is not significantly changed.

It is recommended that the necessary improvements be added to existing SWCT test simulator programs to account for pH changes. Although this will increase the computing cost of matching field data, the effects may be important enough in some cases to warrant the added complication.
Hydrocarbon Composition and Saturation From Pressure Core Analysis
Authors: Treinen R. J. , Bone R. L. , Vogel H. S. , Rathmell J. J.
Published: December 2007

A new method for analyzing pressure cores to obtain quantitative liquid and gaseous phase compositions has been developed. The compositional analysis provides concentration of components including nitrogen, carbon dioxide, and methane through hexatricontanes+ (C36+). Equation of state calculations and material balance data are used to provide saturations of hydrocarbon liquid and gas phases. Previous methods to quantify oil saturation in pressure core samples are based on PVT correlations which are less reliable. Accurate saturations of oil, gas and water in core samples can be obtained with this method even when total hydrocarbon composition changes such as in a gas cap transition zone. The equation of state parameters were obtained by a characterization of PVT data from bottom hole samples.
Application of Combinatorial Algorithms for Description of Reservoir Properties
Authors: Huang XuRi , Keikar M. G.
Published: December 2007

In this study, effectiveness of combinatorial algorithms for describing reservoir properties has been evaluated. Three different types of algorithms: genetic algorithm, simulated annealing, and stochastic hillclimbing method are tested, and the performances of the algorithms are compared through numerical experiments. It was observed that the modified stochastic hillclimbing is the most efficient method for variogram based objective function. The method was also validated by applying it to a case where both variogram and well testing information were available. We concluded that modified stochastic hillclimbing is order of magnitude times faster than the simulated annealing method. The reason for the success of the modified stochastic hillclimbing method is provided through objective function analysis. Finally, the method is applied to a field case to generate interwell porosity distribution.
Mechanistic Study of Carbon Dioxide Flooding Using Horizontal Wells
Authors: Lim M. T. , Pope G. A. , Sepehrnoori Kamy
Published: December 2007

A finite-difference, equation-of-state, compositional simulator has been used to conduct a mechanistic study of carbon dioxide flooding using horizontal wells. We have used the reservoir and fluid properties of an actual West Texas carbonate reservoir that is currently being waterflooded. The phase behavior and properties of the CO2 used in these simulations are typical of those of multiple-contact-miscible (MCM) field conditions of West Texas. Although the equation-of-state MCM calculations require much more computer time, comparison with a first-contact-miscibility (FCM) displacement demonstrates the importance of the more realistic phase behavior description since the injectivity and oil recovery were significantly different for the MCM than for the FCM simulations. All simulations were conducted using permeability fields that have been conditioned with core data taken from two wells in the field. We have compared the performance of the process using a vertical injector and a vertical producer with that using a horizontal injector and a vertical producer combination. We have also investigated the impact of CO2 slug size, skin factor, and relative permeability parameters. These studies show significant sensitivity of the tertiary injectivity of CO2 and brine to the wellbore skin factor and to relative permeability. In tight reservoirs such as that considered in this study, injectivity has a major impact on the efficiency of the process. Although the oil recovery after a given number of injected pore volumes is relatively insensitive to many of the variables investigated in this and earlier studies, the oil recovery at a fixed time such as 20 years varies tremendously since it is limited by the amount of CO2 that can be injected in this time period. This study adds significant new insights and conclusions about the feasibility of using CO2 with horizontal wells.
New Findings From Over Pressure Detection Curves In Tectonically Stressed Beds
Authors: Harper Douglas
Published: December 2007

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

During the last few years, much work has been done on over pressure detection and predictions. predictions. The established rules have been applied, and are reliable in the Delta Country of South Louisiana and Nigeria. In these locales the beds are relatively flat or tectonically relaxed.

Some recent work has been done, utilizing shale densities and drilling data "d" Exponent over a large area that has been tectonically stressed. These areas of concern are the formations around the Andes of South America, the Coastal Regions of California, and Alaska.

The findings of this work seem to bear out the fact that the same rules apply in the tectonically stressed beds as would apply in the relaxed beds of the Delta Country. The big difference is in interpretation of the resulting curves.

In almost all cases in which over pressure could have been predicted prior to drilling, it was best to have at least two curves. These curves may not, in tectonically stressed beds, give the same slope change.

One may trend one direction and the other trend completely reverse. In cases where this has been observed, the fact that the curves changed is the important thing.

The curves have been used in the past on different occasions to predict over pressures, which allows proper pipe setting depth, and to solve problems of hole drag when formation pressure was near hydrostatic or trip pressure. pressure was near hydrostatic or trip pressure. It has been noted on several occasions that abrupt changes in a trend causes concern among the rig crews. This in turn has made them watch pit levels more closely and catch small "kicks" rather than large ones.

Introduction

The Drilling Industry dreamed for years of a way to predict over pressures. This would permit the people involved in drilling a remote "wild cat"' well to determine transition zones while the well is in progress.

Over pressure predictions were made in the past by Electric Logs and by other data compiled from what was termed, Similar Wells. Such practices resulted in wells being drilled with excessive mud weights, and subsequent loss of circulation by induced fracturing.
Miscible or Near-Miscible Gas Injection, Which is Better?
Authors: Thomas F. B. , Holowach Nancy , Zhou XueLong , Bennion D. B. , Bennion D. W.
Published: December 2007

Miscible flooding was invented many years ago, and in the 1950's it was viewed as one of the most promising techniques to use for improving oil recovery from a reservoir.1,2,3,4,5,6,7 Since that time many groups have researched what would be the most important parameters to optimize in the lab, have developed theoretical models to correlate these parameters, and then have implemented these "optimally designed" gas injection systems in the field. Amidst all the increase in technology and sophistication there is still ongoing debate as to whether one needs to achieve miscibility in order to optimize the recovery or whether a degree of immiscibility, characterized by the name "near miscible", is equally adequate for field implementation in enhanced oil recovery processes.

This paper seeks to provide insight into these questions by reviewing some of the parameters which are at work in gas injection EOR as well as qualifying some of the techniques which can be used in designing gases for injection. Moreover, case histories are described herein where laboratory work was performed, phase behavior described, and then the gas injected into the reservoir. Results from the field are then shown and commentary included on the field performance.
An Evaluation of Oil Recovery by Vaporisation
Authors: Espie A. A. , Brown C. E. , Merrill R. C. , Newley T. M. J.
Published: December 2007

Injection of lean gas into volatile oil reservoirs to recover oil by vaporisation is frequently identified as an attractive development option. This mechanism is a significant feature in reservoirs with large-scale gas recycling projects.

A fundamental evaluation of the process has been undertaken for a specific reservoir application to validate our understanding of the physical mechanisms. The local contact efficiency on a microscopic scale and the rescaling of data from the laboratory scale to simulator grid block scale were identified as areas of significant uncertainty.

In this study, accurate measurements of the local contact efficiency for a lean gas stream vaporising residual oil from a gravity drainage process have been made. The experiments were conducted at reservoir conditions using core from the Prudhoe Bay reservoir.

Use of the experimental measurements to validate a field scale model capable of process optimisation requires a number of steps. Firstly, a detailed simulation analysis of the core scale displacement is required to validate the model of the physical process on the microscopic scale. Then, as model length scales increase the effects of heterogeneity become increasingly important. The outstanding steps in the validation procedure are outlined.
Experimental Measurement and Modelling of Transition Zone Fluids
Authors: Nighswander J. A. , Chang-Yen D. A. , Perez Jorge , Kalra Harish
Published: December 2007

Current practice in the evaluation of suitable EOR solvents involves performing a number of slim tube displacement experiments. The information obtained from these tests is generally sufficient for the determination of minimum miscibility pressure (MMP) or minimum miscibility composition (MMC). However, in a standard slim tube displacement test, it is not possible to obtain quantitative information with regard to the phase behaviour of the transition zone fluids. This information is crucial for the development and tuning of compositional reservoir models used for simulating miscible displacement processes. Presently, this information is obtained from static fluid property tests such as P-х (swelling) or Benham multiple contact tests.

In this work, new experimental data for live transition zone fluid properties and compositions generated during a multi-component hydrocarbon displacement process are presented.

In addition, the experimental transition zone fluid properties have been predicted using an equation of state (EOS) model based on a fluid characterization obtained by matching P-х data. Results of these calculations indicate that it is not possible to predict transition zone fluid behaviour for the system under consideration using an EOS characterization based only on P-х data.