bluuebunny/crossref_metadata_2025 huggingface dataset:
Applications of Transient Pressure Interference Tests to Fractured and Nonfractured Injection Wells
Authors: Cooper K. J. , Collins R. E.
Published: December 2007

Transient pressure interference tests have proved to be very effective for determining parameters for reservoir simulation of deep-well, hazardous waste, injection systems. These well systems provide a unique, large-scale laboratory for conducting interference tests in both fractured and non-fractured wells because disposal takes place in single-phase brine aquifers. A number of multi-well systems are described in a variety of geological settings to demonstrate the wide range of systems in which interference testing has been utilized with remarkable success.
Ultimate Recoveries and Economics of Massive Hydraulically Fractured Wells in the Hauptsand, Soehlingen Gas Field, Germany
Authors: Griffiths J. D. , Lepper U.
Published: December 2007

Using a model consisting of a 90° segment of a radial coning simulator the behaviour of massive hydraulically fractured wells is modelled. For the Hauptsand of the field Soehlingen in North Germany, where gas permeabilities are in the microdarcy range, the model has been successfully used to determine rate profiles and ultimate recoveries and, in conjunction with an economic program, to investigate the economic viability of MHF-projects.

For effective gas permeabilities in the microdarcy range, the study shows the importance of achieving a maximum fracture length, of the relationship between formation permeability and economic viability, and of assessing the areal permeability trends in the drainage volume.

The model is used to establish a relationship between gas permeability and drainage volume for the life-expectancy of the well. This allows ultimate recoveries, and hence reserves, to be estimated simply if the average formation permeability is known.
A Deconvolution Algorithm for Analysis of Variable-Rate Well Test Pressure Data
Authors: Mendes L. C. C. , Tygel M. , de Franca Corrèa A. C.
Published: December 2007

Reservoir parameters and flow patterns may be better characterized by well test analysis when bottomhole pressure and sandface flow rates are available. Pressure data which would result from production at constant rate, can be obtained by deconvolution, thus allowing the use of standard interpretation techniques.

This work presents a deconvolution procedure based on the approximation of pressure and rate measurements by combinations of cubic spline functions and the use of Laplace transforms for these approximations. The inversion from Laplace space to real space is carried out by standard numerical algorithms.

Comparison has also been made with three other methods available in the literature. The first one uses the procedure described above but makes a piecewise linear approximation for both the flow rate and the bottomhole pressure, and the other two are based on linearizations of the convolution integral.

Several simulated and field examples are presented.
Technical and Economic Evaluation of Steam Injection With Horizontal Wells for Two Typical Heavy-Oil Reservoirs
Authors: Petit H. J. -M. , Renard G. , Valentin E.
Published: December 2007

The use of horizontal wells can improve the performance of thermal recovery by steam stimulation/drive process. The aim of this study was to evaluate different steam injection strategies depending on the reservoir characteristics, as well as spatial distributions for vertical and horizontal wells.

The field development of two typical reservoirs representative of the conditions encountered in Canada and Venezuela and containing heavy-gravity oils was studied by numerical simulation. The injection strategies applied to the different patterns included the number and the duration of the stimulation cycles, starting time of steam drive, influence of the presence and duration of a following water drive on the final oil production.

The results of the 3-D simulations mainly showed that horizontal well patterns improved productivity, so that projects can be completed in a significantly shorter time in fields where oil productivity is limiting (thin, viscous-oil reservoirs with low initial mobility). It is shown that reservoir conditions (depth, pay zone thickness) have a considerable effect on the injection strategies and therefore, on the oil productions. The extension of the heated zones and the evolution of the steam fronts depending on the spatial distributions of the wells and main reservoir characteristics are also presented in this paper.

The injection strategies applied to the different vertical and horizontal well patterns were compared on an economic point of view, which considers the recoveries and field costs for the processes. Specific advantages of certain well configurations are presented. The economic interest of using horizontal wells for deep heavy-oil reservoirs where steam injection would be economically unprofitable or marginal with vertical wells is shown.
Well Test Analysis in Oil Reservoirs with Gas Caps and/or Water Aquifers
Authors: Al-Khalifa A. J. , Odeh A. S.
Published: December 2007

This paper proposes a new solution for analyzing well tests run in oil reservoirs underlain by water aquifers or overlain by gas caps.

The presence of a gas cap and/or a water aquifer alters the pressure response of wells penetrating the accompanying oil sands. Only a single phase flows into the wellbore while a segregated multiphase flow predominates in the formation. Neither single-phase nor multiphase conventional pressure transient solutions apply for such an environment. Type curves, published in the literature, were developed assuming constant pressure at the gas-oil or oil-water interface. For most practical cases, this assumption appears to distort the physics of flow and results in non-accurate answers.

In this study, a finely-gridded coning model was used to simulate more than a hundred drawdown, buildup and injectivity tests. In contrast to the constant-pressure assumption, the semilog plots of pressure vs time exhibited straight lines reflecting pseudo-radial flow across the entire formation thickness. The semilog slopes were then used to yield the total system transmissibility, (kh/µ)t.

This paper also explains a time-lapse technique which uses successive tests run in the same system to track the location of the oil-water or gas-oil contacts with time. The same technique may also be used to obtain an estimate of the end point relative permeability in the swept zones.
Simple Performance Plots Used in Rate-Time Determination and Waterflood Analysis
Authors: Lijek S. J.
Published: December 2007

The logarithm water-oil ratio or the Ershagi watercut function plotted versus cumulative oil production or oil recovery are commonly used as indicators of waterflood performance because of their inherent linearity. Less well known but similarly justified is the water-oil ratio (more precisely, [1/WOR]+WOR) versus cumulative injection or pore volumes injected plots. Analytical methods by which oil rate as a function of time can be obtained, which is consistent with these performance plots, is shown. With additional correlations for estimating injection or gross (oil and water) production rate, predictions are possible for either the constant rate or constant producing pressure (variable rate) operating strategies.

It is shown that oil rate decline curves obtained using these methods are either hyperbolic or harmonic depending on whether gross rate is constant or variable. Decline curves are simple to calculated and retain their consistency with the performance indicators over a wide span of time.

Application of these methods to the Wilmington Field are shown to be useful in understanding how changing conditions in the reservoir are reflected in performance. Oil rate can be estimated by sand interval based on pore volume injection versus time trends, and on correlations for water-oil ratio as a function of pore volume injection. Thereby the impact of improved verticle sweep efficiency on overall performance can be determined.
Understanding Minimum Sales Price and Maximum Purchase Price
Authors: Daley G. C. , Elmer D. R.
Published: December 2007

Should the federal income tax consequences of an acquisition or disposition of a property affect the price that a buyer should pay or a seller should receive?

Capital gains tax paid on a property sold is a definitive cash consequence which the seller pays. The tax impacts the net cash received and must be included when compared to value given up in the disposition of a property. In order to have sufficient cash to pay the capital gains tax and receive the present value of the future cash flows of a property, the sales price must be a multiple of the present value. The required sales price (or minimum sales price, "MSP") has been reduced to one of three single equations depending on the tax position of a firm. A non-dimensional one line graph is used to depict the relationship between sales price and present value when the capital gains tax rate is the same as the ordinary income tax rate. A complete overview of MSP and the factors which influence its computataion (present value, tax rate, recapture, "lax clawback", investment tax credit, and current tax basis) is presented.

Similarly, the purchase of a property will allow the purchaser certain tax benefits which generate more after tax value than only the present value of the cash flows of the purchased property prior to sale. The purchase price is allocated to tangibles and intangibles for tax purposes and is then depreciated and depleted on the tax books. This decreases the amount of income tax that the buyer is required to pay, and results in a purchase price which is a multiple of the present value prior to sale. Two non-dimensional graphs assist the reader in understanding the MPP process and the factors which influence its computation (present value, tax rate, property life, production decline, and the fractional allocation between tangibles and intangibles).

These concepts are used by most major oil companies and some independents. An understanding of how these concepts operate will give the reader an insight into why large properties are purchased and sold at values different than their present value of operations.
An Integrated Approach to Developing a Small Offshore Field: Scapa Field, North Sea
Authors: Chen H. K. , McGann G. J. , Romani R. S.
Published: December 2007

The Scapa Field is located 112 miles north east of Aberdeen in the U.K. sector of the North Sea. The field was discovered in 1975. It is developed with an integrated production/injection subsea template system, tied back to the main Claymore platform. Production commenced in 1985. Initial reserves are estimated at 65 million barrels. Current production is about 27,000 B0PD from four production wells with pressure maintenance through four injectors. A total of seven appraisal wells have been drilled.

The field is located in a SE-NW trending syncline, with onlap termination of the lower Cretaceous reservoir to the north onto the Claymore High. Faults terminate the field to the west and south.

The reservoir in the field is the Scapa Sandstone Member which is typically 100’ thick, at a mean depth of about 8300’. The sands are turbidites, typically fine to medium grained with permeability averaging about 200 md. The reservoir section is characterized by abundant calcite cemented concretions. The average reservoir bed thickness is about one foot.
The Economic and Operational Results of the Long-Term Stackout of a Land Rig
Authors: Holm D. W.
Published: December 2007

The principle purpose of this paper is to evaluate the effects of long term land rig storage on the economics of returning a rig to service and the operational performance that may result.

This evaluation includes an example, with discussion, of the actual results of returning a stacked rig to service.

The paper discusses the general procedures and costs associated with the initial preservation of the rig, the preventive maintenance required to maintain the rig while stacked, a description and cost of the work required to return the rig to service, and the performance of the rig in the field in terms of downtime.

Problem areas of land rigs stacked on a long term basis are reviewed.

The paper concludes with a discussion of what can be expected of rigs that have not been properly preserved and/or prepared for return to service.
Survival Craft Training for the Offshore Industry
Authors: Lund G. L. , Zambon F.
Published: December 2007

As a result of marine disasters in the Offshore Petroleum Industry, there has been an increased emphasis on the training of marine safety. The U.S. CoastGuard has proposed licensing requirements for the Mobile Offshore Drilling Units (MODUs) that will mandate training in the enclosed lifeboat (covered powered survival craft) and survival suits. An analysis will be made of the traditional training currently implemented, international standards of training, recently proposed Coast Guard required training, and how to determine task analysis for this type of training. We will look at methods of validating objectives and training along with the practicality of hands on training with actual equipment in the work environment versus simulation. The relationship of formal training and the currently required drills will be discussed and how they can effectively complement each other. The methods of research included historical evidence, behavioral studies into training, current recognized standards of training, and field surveys. Also, a case study using a pre-test, and a random selected subgroup for a performance re-test will be analyzed. The study identifies needed training and concludes that the emphasized principles of instruction should be: a simple presentation; the concentration on fundamentals; the minimization of lecture; and the provision of hands-on practice. Safety limitations will dictate how realistic any training can approximate the actual tasks and conditions to test the students skills. A combination of actual and simulated hands-on exercise along with classroom instruction will optimize the learning procedure. For maximum retention formal training should be reinforced with regularly scheduled drills and instruction at the work site. Feedback isthe key to analyzing the effectiveness of the training.
Bit Balling in Water-Reactive Shale During Full-Scale Drilling Rate Tests
Authors: Cheatham C. A. , Nahm J. J.
Published: December 2007

This paper demonstrates a useful means of studying bit balling in laboratory drilling tests. Full-scale tests were conducted using a new 6-1/8 in. (156 mm) tricone insert-type bit, realistic muds, and Pierre shale, which is similar to water-reactive shales which are apt to cause balling in the field. Balling ranged from slight to severe with an uninhibited water-base mud, and did not occur with an oil-base mud. The ratio of bit torque to weight-on-bit was a reliable indicator for detecting the degree of balling. The results show that proper modeling of bit balling in the laboratory must address the degree of overbalance which results from insufficient mud weight in the field. They also indicate that increasing mud weight, in the field is an effective means to reduce or prevent bit balling if, and only if, balling is caused by mechanical (not chemical) wellbore instability. Although bit balling would become (irreversibly) severe within seconds, it could be prevented by significantly reducing weight-on-bit quickly enough after incipient balling.
The Development of the Furrial Field with Innovative Drilling Framed Within the Philosophy of Improvement of Quality of Work
Authors: Perez F. E. , Sanguino J. E. , Cumana J.
Published: December 2007

Since the completion of the first exploratory well in 1986 until June of 1989, LAGOVEN has put on stream a total of 15 wells averaging a daily production of 100.000 BPD of medium API gravity oil in this 32.000 acres field. To drill these deep, high pressure, high temperature wells, a series of tecnnological innovations has "been introduced which have allowed us to reduce the drilling time from 24 days/1000 ft to 4*7 days/1000 ft, averaging lately a drilling cost of 358 $/ft which is 40% lower than the world's average of 592 $/ft.

To reach this goal, LAGOVEN has developed and adapted several techniques and operational practices, together with a project directed to create the optimum drilling organization all framed within the scope of the philosophy of improvement of quality of work. Among the most important ones we could mention: the creation of a task force to manage the drilling project, adjustments in the designs of surface locations, well heads, drill and casing strings, hit, muds, cement, perforating guns and the implementation of dual completion systems.

The objetive of this work is to describe the evolution of the drilling activity as well as of the human resources that has allowed LAGOVEN to develope The Furrial field in a very optimized manner, by applying the philosophy of improvement of quality of work.
Cement Spacer Fluid Solids Settling
Authors: Moran L. K. , Lindstrom K. O.
Published: December 2007

In recent years emphasis has been placed on the use of "turbulent flow" spacers. Normally this practice helps in obtaining higher drilling fluid displacement efficiencies, and thus a good cement job. However, depending on placement rates, well geometry, etc., the solids required in these relatively thin spacer fluids can settle even in dynamic conditions. This problem is manifested in deviated wells by a channel of solids forming on the low side of the pipe and annulus. This channel of solids prevents placement of a continuous cement sheath in the annulus, providing a potential path for interzonal communication.

To develop a better understanding of this phenomenon, a full scale laboratory investigation was conducted using field mixing equipment and a large scale, simulated wellbore test facility. Factors evaluated for their influence on spacer settling included (1) various pipe geometries, (2) pipe centralization, (3) fluid rheological properties and composition, (A) flow rates, and (5) well deviation angles. As a result of this investigation a mathematical correlation was developed to predict minimum flow rates required to alleviate spacer solids settling in highly deviated wells. It is apparent from these test results, that achieving turbulent flow is not the sole criterion for obtaining optimum spacer efficiency. This paper presents test procedures, equipment descriptions, and discussion of results, in addition to a full definition of the problem of spacer settling.
Adsorption Characteristics of PHPA on Formation Solids
Authors: Liao W. A. , Siems D. R.
Published: December 2007

One of the most important uses for polymers in drilling fluids is shale stabilization. The shale stabilizing mechanism is not very well understood, but many think it results from hydrated polymer molecules interacting with water and shale surfaces by a process of adsorption. Adsorption is a complex surface phenomenon. Measurement of solution viscosity may not be adequate to quantify the adsorption characteristics of polymers. This study focuses on the static adsorption of a partially hydrolyzed polyacrylamide polymer (PHPA) on formation solids. The study also investigates various factors affecting adsorption of polymers. The adsorption was quantified by adsorption density, which is the amount of polymer adsorbed per unit surface area of solid particles. Application of laboratory findings to field situations is also discussed.
The Development of an Inhibitive Cationic Drilling Fluid for Slim-Hole Coring Applications
Authors: Beihoffer T. W. , Dorrough D. S. , Schmidt D. D.
Published: December 2007

This paper describes a new inhibitive cationic drilling fluid developed for slim-hole coring applications. High rotational speed slim-hole coring requires a drilling fluid that will maintain a gauge hole to preserve the bearing-like tolerances between the drillstring and wellbore. A low-solids fluid is also required to prevent drill solids from centrifuging inside the drillstring. This paper describes both the laboratory development and field testing of the drilling fluid.

Conventional water-based drilling fluids rely on dispersed clay for viscosity and fluid loss control. Negatively charged (anionic) materials are often added to the fluid to inhibit reactive shale formations. In this study, additives with a positive charge (cationic) were investigated as shale stabilizing agents.

The study found that quaternary ammonium salts (cationic surfactants) gave high recoveries in the shale rolling test. The ability of the surfactants to stabilize shale was found to vary with chemical structure. Despite their ability to stabilize shale, the surfactants were unsuitable for use in drilling fluid formulations because of their tendency to foam. Low-molecular weight synthetic cationic polymers that contain structures similar to the surfactants gave shale recoveries as great as the surfactants but without the foaming problems. The combination of potassium chloride with cationic polymer resulted in shale recoveries greater than with either component alone.

Drilling fluids were formulated based on a combination of a cationic polymer and KCl. Initial work indicated that many commercially available drilling fluid additives were incompatible with the cationic polymer. Additives were found that were compatible and provided satisfactory drilling fluid properties. Field testing of a cationic/brine drilling fluid suggested that the fluid was highly inhibitive when compared to close offset wells drilled with conventional water-based drilling fluids. The fluid was compatible with the slim-hole high rotational speed coring system.
Material Balance Concepts Aid in Solids Control and Mud System Evaluation
Authors: Dearing H. L.
Published: December 2007

Evaluation of the entire system of solids control equipment and control techniques and the mud system can be accomplished by using several simple concepts and understanding their interrelationship. The concepts of solids removal efficiency, mud usage, and equilibrium drill solids can be related together with a simple equation. These concepts are used to post analyze wells, illustrating typical drilling fluid and solids control problems. Solutions are suggested with quantified results needed for economical applications.
Downhole Gas Detection Method in Drilling Fluids
Authors: Vestavik O. M. , Aas B. , Podio A. L.
Published: December 2007

Gas entering the well during drilling operations may often lead to expensive well problems and can sometimes lead to disastrous blowouts. In order to find improved methods for early detection of gas, the possibility of using an acoustic interferometer has been investigated. This work shows that interferometric measurements are very sensitive to the presence of free gas in liquids. The acoustic interferometer has the potential to become an effective method for the early warning of gas while drilling. It would be especially valuable when drilling in areas with shallow gas zones. The interferometer is judged to be applicable for MWD.
Environmental Directionality Considerations in MODU Location Assessments
Authors: Malcolm B. G. , Cowgill C. F.
Published: December 2007

The effects of considering environmental directionality in the assessment of Mobile Offshore Drilling Unit (MODU) locations are examined in this paper. A specific North Sea jack-up location is reviewed.

Traditionally, the suitability for operation of a MODU at a given location is determined by simultaneously applying the maximum design wind, wave, and current values simultaneously from the worst possible directions for assessing stresses, overturning moments, etc. These environmental loads are treated as a quasi-static load case. Stresses, overturning moments, and preload requirements resulting from this extreme load case are estimated and compared to design allowables.

Many site-specific assessments are now beginning to include second-order effects and are also attempting to evaluate the dynamic responses of MODU's. Peak static loads and peak dynamic loads do not necessarily occur simultaneously. The possibility of overly conservative load and stress predictions exists if an extreme environment is simultaneously applied from the worst directions in these evaluations.

An argument for considering rig orientation and environmental directionality is presented. Results obtained from a directionality assessment are reviewed. It is concluded that site assessments based on environmental directionality considerations are a reasonable and prudent indicator of safe MODU locations.
Drilling With Semiautomatic and Automatic Horizontal Racking Rigs
Authors: Deguillaume J. , Johnson B.
Published: December 2007

While ELF has started exploration under the city of Paris, the Paris Basin remains the area of FRANCE where the activity is relatively important with the most promising recently discovered oilfields.

The high drilling activity during the years 84 to 86 in the Paris Basin area of France has led to a significant optimization of all operational conditions for realizing medium depth wells (between 6000 ft and 9000 ft). It was possible by improving drilling factors as bits, mud and directional drilling but also by the strong development of turnkey and incentive day rate contracts and the introduction of semi-automatic and automatic rigs. New concepts, mechani-zation and automatization are more than ever a must to enable drilling to take place in an urban environment. At the same time, automatization of rigs will increase work safety and also reduce cost footage.

Two new rigs were introduced for realizing wells with a lightened 6" "slim hole" drilling programme to a T.D. of 6000 ft to 8000 ft : their names are FORAMATIC 1 (end of 84) and FORAMATIC 2(end of 85).

At these depths the FORAMATIC 1 and 2 not only give the advantages of reduced crews, less civil engineering and environmental impact, increased safety and good drilling performance but significantly decrease the cost of drilling a well.

This paper gives a technical presentation of both rigs, after reminding machineries which have been built with similar concepts. Advantages and drawbacks of FORAMATIC rigs are brought out by considering field performances and procedures in Paris Basin area. Special attention is beared on the FORAMATIC 2 rig where automatic tripping is possible and a real time data monitoring has been developed.
A New History-Matching Technique in Simulating Steam Injection Projects
Authors: Ying A. N. , Dougherty E. L. , Wang S. W.
Published: December 2007

As previously reported1,2,3, a scaled physical model was developed to study the oil recovery efficiency of steam injection into horizontal wells. Experimental performence evaluations were made with two types of synthetic oils with injection of steam at different qualities. In this paper, the results of these laboratory studies are compared to predicted performance using a three-dimensional, three-phase thermal simulator.

Previously, most history matching studies have relied heavily upon adjustments to the relative permeability curves to obtain agreement between calculated and observed production data. In this study, to match production data we devised a new technique in which at elevated temperatures oil viscosity is lowered and water viscosity is increased so as to converge to a common value at steam temperature. Conceptually, this technique implies that at steam temperature oil and water tend to form as a combined emulsion phase. The presence of an emulsion phase is evidenced by experimental studies and thermal oil production in the field.

We successfully used the proposed technique to match the oil and water production data obtained from laboratory experiments. The efficacy of the technique demostrated by comparing observations to three separate prediction runs; (1) base case using standard relative permeability and viscosity data (2) results computed with only relative permeability adjusted, and (3) results with only viscosity adjusted. The history matching studies include oil production from vertical wells in a five-spot pattern and horizontal wells in a trench pattern.
Appraisal of Analytical Steamflood Models
Authors: Chen H-L. , Sylvester N.D.
Published: December 2007

Steamflooding in heavy oil reservoirs is one of the principal thermal oil recovery methods. This paper evaluates principal thermal oil recovery methods. This paper evaluates the existing analytical steamflood models with respect to their mechanisms and predictive capabilities and compares them with field data. The three steamflood models selected were: a frontal advance model [Jones (1981)], a modified frontal advance model [Farouq Ali (1982)], and a vertical gravity override model [Miller and Leung (1985)]. Each model was somewhat modified to improve its ability for the prediction of production rate and/or history match of typical field production rate and/or history match of typical field production data. production data. The Jones steamdrive model, with its empirically determined scaling factors, was found to give a reasonable history match of oil production for the Kern River field. Fields with different characteristics will require an adjustment of these scaling factors and/or field property data to achieve an acceptable history match. The modified Farouq Ali steamdrive model gives a good history match without need for empirical factors or adjustable parameters. It is thus recommended for the prediction of steamdrive oil recovery when field production data are unavailable. The Miller-Leung gravity override steamflood model, which contains two adjustable parameters, was found to possess the best overall history matching Capabilities and is recommended for this purpose. purpose.

Introduction and Literature Review

The injection of steam into heavy or pressure depleted oil reservoirs has been a successful enhanced oil recovery process for more than three decades. A principal application process for more than three decades. A principal application of the steam injection is steamflooding which is also termed steam drive or steam displacement. In this process, steam is continuously injected into a number of injection wells, and the displaced fluids are produced from the production wells. Ideally, the injected steam forms a steam saturation zone around the vicinity of the injection well. The temperature in the steam zone is nearly equal to that of the injected steam. Moving away from the injection well, the steam temperature drops gradually as the steam expands in response to the pressure drop and heat losses to base formations. At a certain pressure drop and heat losses to base formations. At a certain distance, the steam condenses and forms a hot-oil bank. In the steam zone, oil is displaced by the steam. In the hot oil zone several changes take place which result in oil recovery. They include heat losses the formation, thermal expansion of the oil, and reduction of oil viscosity. In addition, residual saturation may decrease and changes in relative permeability may occur due to the variations of temperature and saturation.
The Effect of Surface Phase Splitting on Project Oil Recovery
Authors: Hazlett W. G. , Mims D. S. , Walzel M. D.
Published: December 2007

This paper presents the results of an investigation of the effects of surface phase splitting and project interaction on oil recovery. The study utilized a multi-pattern, generic model with typical Kern River reservoir properties. The major result of this study is that surface phase splitting within a homogeneous, preheated, nine pattern project does not appear to have significant effect on either oil production rate or cumulative oil production. In addition, oil recovery within a particular project was shown to be greatly affected by neighboring projects.
Performance Correlations for Steamflood Field Projects
Authors: Torabzadeh S. J. , Kumar M. , Hoang V. T.
Published: December 2007

Actual steamflood field performance data show that the shape of the oil recovery curves is generally different from simple predictive models that are currently used, such as Gomaa's correlation (which is based on symmetric element simulations) or analytical models. This paper presents a method and shows how actual field data can be used as a more accurate predictive and diagnostic tool. It was found that normalized oil recovery (fraction of mobile oil-in-place) vs. steam injection (heat injected/ volume or pore volume cold water equivalent) provides a uniform basis to compare and evaluate different projects quantitatively.

Normalized performance histories for various projects in the same field were similar, indicating that histories of previous projects can serve as a preliminary predictive tool for future projects. The normalized curves were correlated with reservoir parameters and operating conditions, using a stepwise, multiple-variable, linear regression method. A new procedure was developed and correlations were obtained for the data in this study. However, no single correlation could be found for all projects. Improved correlations were obtained when the projects were subdivided into two groups, based on predominant production mechanisms.
Large-Scale Facility Expansion Evaluations at the Kuparuk River Field
Authors: Weiss J. L. , Masino W. H. , Starley G. P. , Bolling J. D.
Published: December 2007

Decisions concerning future development options at the Kuparuk River Field are complex and interrelated. Various development strategies are being evaluated. To help address these issues, a facilities model has been added to a full field reservoir simulator. Facility limits are used with a well ranking system to shut in marginal production when equipment capacity constraints are exceeded. The model simulates field operating strategies which maximize production. Operational strategies are modelled using (1) a wellbore hydraulic routine that enables bottom hole pressures to change (reflecting the benefit of various gas lift rates), (2) a gas lift allocation correlation that was determined from field data, and (3) a gas management routine which optimizes oil production while honoring gas capacity constraints and field gas lift needs. These gas management and hydraulic features are essential to properly evaluate future projects in a gas capacity constrained environment and can be applied to other reservoir simulation tools. An example of how the reservoir simulator is being used to address a key issue in the large scale facility expansions evaluation is included.
Dos Cuadras Offshore Polymer Flood
Authors: Dovan H. T. , Hutchins R. D. , Terzian G. A.
Published: December 2007

An offshore polymer flood in the Dos Cuadras field near Santa Barbara, California was implemented early in 1986. The polymer selection process included laboratory screening and a month long field injectivity test with three prospective polymer suppliers. Polymer injectivity, required polymer concentrations to meet design viscosities, the need for additional polymer inversion chemicals and core plugging behavior of the polymer solution were critical parameters in this evaluation. Full-scale equipment design was aided by observing the performance of skids supplied by each vendor for polymer inversion and injection. Following the selection of a polymer product, shear tests were conducted to improve polymer solution injectivity through Berea core plugs. Although these tests were sufficient to ensure injection into the EP zone, additional shearing of the polymer solution was required to improve injectivity into the FP zone. A filtration test, which was found to be more sensitive than the core plug test to the plugging behavior of polymer solutions, was used to compare properties of injected solutions for the FP zone, Hall plots have been found to be useful for understanding the response of the injection wells to the various injectants.
Evaluating the Effectiveness of Corrective Actions Involving Groundwater
Authors: Johnson W. B. , Jennings K. V. B.
Published: December 2007

General methodological recommendations and relevant specific literature references are provided for determining when ground-water cleanups are complete. These methods can be used for cleanups required after spills from gas stations, pipe leakage, tank failure, and petro-chemical processing accidents.

The primary premise of this paper is that the degree of cleanup is defined by more than simply establishment of numerical thresholds. Measurement control, sampling methodology, and data analysis methodologies also influence the degree of cleanup.
Further Characterization of Surfactants as Steamflood Additives
Authors: Hamida F. M. , Demiral B. M. R. , Shallcross D. C. , Castanier L. M. , Brigham W. E.
Published: December 2007

It has been known that steamflood efficiency can be increased by adding surface active agents to steam such that foam can be generated, preferentially reduces permeability to steam in previously invaded zones, and diverts it through undepleted regions of the reservoir. In this study the partial results of a continuing project which aims to optimize surfactant use as additives in steamflood field applications are reported. Two steps of the project were completed up to date. As a first step, the foamability of seventeen surfactants was evaluated at steam injection conditions (160 °C and 75 psig) and linked to their chemical structure. As previously reported by D. C. Shallcross et.al.1, a linear model saturated with only water was used to compare and characterize different surfactants as steamflood additives. During the experiments surfactant solutions were injected as slugs into the sand pack after steam breakthrough. Nitrogen was injected as a noncondensible gas. The evaluation of foamability is based on pressure gradient changes and steam mobility reduction along the model. Under the conditions of the experiments, the alpha olefin sulfonates generated the strongest foam at low concentrations. Internal olefin sulfonates, linear toluene sulfonates and linear xylene sulfonates all generated stable foams at higher concentrations. Flow resistance due to foam also increased as the alkyl chain length increased.

In the second step, first the previous experiments were repeated by using eight selected surfactants to check if they were reproducible. During the runs two 10% PV slugs of surfactant solution with 0.5 weight percent concentration were injected into the sand pack. The second slug was injected after the foam created by the first one completely collapsed. Then these runs were repeated under the same operating conditions as the water runs except for the presence of oil. West Newport crude oil was used at residual saturation after steam flooding during these runs. The analysis of the results showed that both the pressure gradients and the reduction in steam mobility after surfactant solution injection were affected by the presence of oil. In the presence of oil no increase in pressure was observed to date.

The two sets of experiments were compared and discussed in detail using maximum pressure drops and duration of pressure changes, pressure increases with distance from the inlet and time, steam mobility reduction, and thermal parameters. One interesting result is the fact that relative permeability to steam was reduced to between 0.005 and 0.02 when no oil was present.
Laboratory Design and Field Demonstration of Steam Diversion with Foam
Authors: Djabbarah N. F. , Weber S. L. , Freeman D. C. , Muscatello J. A. , Ashbaugh J. P. , Covington T. E.
Published: December 2007

Mobil conducted a foam-steam diversion test to achieve the following objectives:

Confirm laboratory results which show foam generation with steam in unconsolidated sands. Establish the feasibility of steam flow diversion by foam in complex reservoir sands. Determine the effect of varied injection strategies on the steam-foam generation process, and Determine incremental oil recovery attributed to foam.

Laboratory experiments are presented which evaluate foaming surfactants at simulated steamflood conditions using reservoir rock and fluids. Surfactant loss due to adsorption, partitioning, and thermal decomposition are all included, together with displacement results in sandpacks. It is shown that foam will form and propagate at steamflood conditions. A satisfactory injection strategy involves continuous balance between surfactant loss and foam propagation.

Feasibility was demonstrated in a heavy oil reservoir in two contiguous ten-acre inverted nine-spot patterns. Foam, generated at the surface by mixing surfactant with a noncondensible gas (and steam) and injected in a reservoir-specific intermittent on/off cycle, was maintained in the reservoir, as proven by injector wellhead pressure increases. Tracer tests and casing gas analyses showed that foam redistributed steam across the vertically heterogeneous oil sand, increasing volumetric sweep and oil production. Approximately 178,000 lbs of surfactant and 15 MMSCF of nitrogen were injected.
Experimental Studies of Capillary Pressure Effects of Foams in Porous Media
Authors: Chen H.-L. , Ke M-J. , Chuang T-K. , Flumerfelt R. W.
Published: December 2007

Although foams have been recognized for improving in oil recovery process, detailed descriptions of the relative importance of viscous and capillary effects are still lacking. Previous work has largely been concerned with the measurement of effective viscosities or dispersed phase permeabilities which masks both viscous and capillary effects. A first step in separating such effects requires the measurement of capillary pressure for foam systems in porous media. To date, only isolated data of this type have been reported.

In this work, a capillary pressure cell has been designed to investigate capillary behavior of foams in bead packs. This experimental setup has several unique and versatile features such as: (1) Hydrophobic and hydrophilic membranes placed at the entrance and exit ends of the bead pack to selectively restrict the flow of gas and liquid to and from the cell and hence insure correct capillary pressure (PC = PG-PL) measurement; (2) a compression spring imposed on the top of the bead pack to insure a stable bead pack and good capillary contact between the bead pack and the membranes; and (3) back pressure control to allow high pressure testing and to minimize in situ bubble size changes (compressibility effects) during testing. With the above system, sequential drainage and imbibition cycles can be repeatedly traversed without interruption.

Multicycle drainage and imbibition experiments were performed under conditions where the foam was generated in situ, and the static capillary effects were obtained for both non-dispersed phase (gas-water system with no film stabilizing surface active agents) and dispersed phase (surface active agent present) systems. While only two drainage-imbibition cycles are necessary for non-dispersed

phase systems to achieve invariant capillary pressure curves, 4 to 6 cycles are required for dispersed phase systems. In all cases, the irreducible and residual wetting phase saturations at the end of drainage and imbibition are lower than for those of non-dispersed phase systems. Studies of pore structure effects provide direct evidence that dispersed phase systems effectively reduce the degree of heterogeneous behavior in a bed. Studies of wetting effects show that both the irreducible and residual saturations at the end of drainage and imbibition are significantly decreased as the degree of oil wettability is increased. Finally, from tests at different surfactant concentrations, the largest changes in gas trapping occur as the concentration is increased below the CMC (critical micelle concentration); at higher concentrations additional trapping takes place but the effect is less dramatic.
Mechanics of Bubble Flow in Heavy Oil Reservoirs
Authors: Islam M. R. , Chakma A.
Published: December 2007

A new mechanism of fluid flow in solution-gas drive heavy oil reservoirs is identified through experimental studies. This paper presents experimental results in order to verify previous hypothesis on fluid flow in heavy oil reservoirs in Canada. It has been postulated that solution-gas drive in these reservoirs involves simultaneous flow of gas and oil. However, gas remains in tiny droplets under reservoir conditions1. A new mathematical model was proposed in order to describe peculiar pressure-dependent multiphase flow properties. This paper presents experimental validation of some of the hypotheses offered by Smith1. More than 40 experimental tests are performed both in a capillary tube and in a core packed with unconsolidated reservoir fluids and sands. The effects of decreasing bubble size on total fluid production and pressure drop across a pipe are observed. Experiments with live oil and reservoir sands enable one to quantify the contribution of bubble flow in solution gas drive process involved in heavy oil reservoirs. Some of these results help explaining the anomalies observed in heavy oil reservoirs in Canada.
An Automated System for Closed-Chamber Drillstem Testing
Authors: Poulsen D. K. , Bass A. O.
Published: December 2007

Because of its many advantages, including safety, accuracy, and instantaneity, closed-chamber drill stem testing continues to gain popularity as a well testing technique. Although commonly performed, closed-chamber tests typically require manual reading of pressure gauges and manual recording of data.

This paper will describe a computerized system for automatic collection and analysis of closed-chamber test data. Using an IBM-compatible micro-computer and newly developed correlations, the system calculates maximum surface pressures vs. time for pure gas, gas-saturated water and gas-free water influx and displays the curves on the computer's screen. During the test, it reads from any of up to three pressure transducers, records the surface pressures and instantaneously displays them on the pretest planning graph. Following the test, it calculates flow rates for assumed pure gas and pure water flow and, as requested, plots pressure or either of the two rates versus time.

In addition to the computerized system for acquiring the data, the paper will describe and diagram the manifolding system for measuring the surface pressures. The manifolding system was designed to (1) enable pressures to be read from any of a set of three transducers, (2) keep the transducers in a relatively safe area away from the rig floor, (3) tap the chamber's surface pressure at the control head instead of at the floor choke manifold, thereby eliminating chicksan hoses and swings and the accompanying potential for pressure leakage, and (4) allow components to be removed relatively easily for servicing.

In summary, the paper will describe (1) the computerized system for acquiring closed-chamber DST data, (2) the enhanced and newly developed correlations and (3) the transducer manifolding designed for these tests. Diagrams of the manifolding and examples of tests will illustrate the paper.
Solvent/Surfactant Well Stimulations
Authors: Sonka J. K.
Published: December 2007

This paper describes a method to optimize well stimulation treatments using a combination of solvent and surfactant with a jet washing tool to clean clogged liners and perforations. The well selection criteria perforations. The well selection criteria using geologic and production data have been developed to maximize project profitability.

The jet tool is used to selectively place the chemicals in an underpressured reservoir across a large (350-foot plus) completed interval. The chemical used for these jobs is xylene and a nonionic surfactant/demulsifier. The surfactant is mutually soluble in hydrocarbon and water. Xylene acts as a carrier for the surfactant and solubilizes asphaltenes. This combination of xylene and surfactant breaks emulsions and makes the gravel pack and/or formation near the wellbore water-wet.

Twenty-seven wells have been stimulated in the North Midway Sunset Field. The optimal concentration range of surfactant was found to be between 9 and 14%. Treatments using surfactant concentrations in this range have rapid payout.