bluuebunny/crossref_metadata_2025 huggingface dataset:
Using Heat in Combination With Solvents To Clean Up Formation Flow Channels
Authors: Rollins J.T. , Taylor L.C.
Published: December 2007

A new stimulation technique has been developed for restoring blocked permeability in both injection and production wells. The method utilizes a combination of heat and chemical solvents to remove organic and inorganic deposits that have accumulated in formation flow channels and on the face of the wellbore, during operation. The treatment is conducted in two-stages. First, a gelled oil, carrying a suspension of 20–60 mesh magnesium pellets, is injected into the pay zone. This is followed by 15 per cent hydrochloric acid which, reacting with the magnesium pellets already in the well, liberates considerable heat (8,400 BTU/lb of magnesium). As a result, the temperature of the formation may be raised several hundred degrees. The spent acid is now produced from the well, followed by the oil which has picked up many paraffin and asphalt deposits liquefied by the liberated heat. In addition, the acid solution used to release the heat reacts with any lime, oxide or sulfide deposits on the face of the pay, dissolving and removing them. To date, this new heat application has been successful on about 60 per cent of production and injection wells treated. Many of these wells have failed to respond to other type treatments. As refinements and improvements are made in treating procedures and selection of wells for treatment, a higher success ratio may be expected.

Introduction

Many wells show good output after initial stimulation treatments, but after a short time production falls off more rapidly than would be expected on the basis of formation pressure and permeability. The cause for such abnormal declines is usually either an equipment failure or change in formation characteristics. In the latter case, the trouble is frequently caused by some foreign material which partially plugs the flow channels, hindering the migration of reservoir fluids into the wellbore. Such plugging may result from either organic or inorganic mineral deposits, or both. The buildup of organic deposits often results from a decline in reservoir pressure which allows dissolved gas to break free.
The Effect of Foam on Surface Kinetics in Fracture Acidizing
Authors: Ford William G.F. , Roberts Loy D.
Published: December 2007

A method of calculating acid spending of foams in a fracture has been developed. Experimental data are presented for foamed acid flow in limestone and dolomite laboratory-prepared fracture systems 60 in. [152.4 cm] long at 70 deg. F at [21.1 deg. C]. The surface reaction in an HCl-limestone system is fast compared to the mass transfer to the rock surface. The overall acid spending rate is to a large degree dependent on the extent of fluid mixing in the fracture. This is called a mass-transport- or diffusion-controlled reaction. The surface reaction rate in an HCl/dolomite system is finite compared with the rate of mass transfer to the rock surface. This is called a "kinetic-controlled" reaction. Earlier work showed that whether the acid was gelled or weighted, diffusion control still would be dominant for the HCl/limestone system and kinetic control would dominate the HCl/dolomite system. A method of predicting the penetration of foamed acid is presented based on combining the mass transfer coefficient of the acid in the fracture with the surface reaction that occurs at the fracture surface. Example calculations are presented to show the effect of various variables,

Introduction

The use of foamed acid in fracture acidizing treatments has gained widespread acceptance in the past few years. Various properties of foamed acid have been investigated and its successful use in stimulation treatments has been reported. Surface reaction kinetics in fracture acidizing have been studied for nonfoamed systems by several authors. This paper describes work where acid spending of foams has been measured directly and the effect of foam on surface kinetics in fracture acidizing has been studied. Laboratory data are presented that describe the effects of foam quality, foam flow rate, and foam stabilizers on the surface reaction kinetics of foamed acid on limestone and dolomite.

Mathematical Model

A mathematical model describing the spending of foamed acid was developed similar to that presented earlier by Guin and Roberts. The model for foamed acid spending is illustrated in Fig. 1. The foam leakoff velocity, V, is assumed constant over the fracture length. Assuming the foam quality is constant and there is steady-state flow in a vertical fracture, the mass balance equation for foam in a fracture is

(1)

where u and V represent the foam velocity components in the x and y direction, respectively. Gamma represents the foam quality (volume fraction of N in foam) and C the concentration of acid in the foam. (D+D ) represents the effective diffusivity. Eq. 1 must be solved subject to the following boundary conditions.

(2a)

(2b)

(2c)

The velocity components u and V are functions of x and y, satisfying the continuity equation:

(3)

These partial differential equations can be transformed into ordinary differential equations (Appendix A) to give

(4)

(5)

and

(6)

Eqs. 4 through 6 were derived by following the procedures proposed by Roberts and Guin for acid penetration for plain acid fracture treatments.

JPT

P. 89^
Optimal Reservoir Production Scheduling By Using Reservoir Simulation
Authors: See Bertrand A. , Horne Roland N.
Published: December 2007

This paper addresses the optimization of field operations under a given set of technical and economic constraints and demonstrates that an optimal control procedure may be applied to any industrial oil and/or gas reservoir at reasonable cost and at acceptable accuracy level. Both primary and secondary recovery processes can be considered.

The method proposed here is presented in two main sections. First, the modeling phase provides an approximately and locally linear model of the reservoir. A previously calibrated reservoir simulator model is used to perform a series of experiments, and a multiple variable regression analysis is used to fit the experimental data. The experimental design was one of the key issues in this work. Second, the optimization phase is performed with a linear programming algorithm. Nonlinear effects, such as those generated by the presence of gas, are approximated by several procedural iterations.

The application of this method to the case of a hypothetical reservoir demonstrates the validity of the optimal control procedure and shows convergence within an acceptable number of iterations.
Recovery of Retrograde Condensate from Naturally Fractured Gas-Condensate Reservoirs
Authors: Castelijns J. H. P. , Hagoort J.
Published: December 2007

This paper considers the flow behavior of retrograde condensate in naturally fractured gas-condensate reservoirs and the possibility of recovering part of the condensate by gravity drainage. The analysis is applied to calculate the potential for retrograde condensate recovery in the Waterton reservoir in Alberta. The calculated results are in agreement with field observations: for fracture density, matrix permeability, and reservoir-layer thickness typical of the Waterton reservoir, a small part of the retrograde liquid will accumulate within a practical time span. Condensate accumulation and recovery will significantly increase if the reservoir pressure is restored—e.g., by lean gas or nitrogen injection.
Centralized Automatic Production Control and Data Gathering in the Virginia Hills Field
Authors: Cleland Noel A.
Published: December 2007

A centralized automatic control and data-handling system has been installed in the remotely located Virginia Hills field of Alberta. It permits the automatic or manual control of the whole area from one point and gathers all data at the same point. The design uses a parallel-transmission multiplexing system for control and data handling. Data-generating devices give a digital output. The mechanical installation under control is outlined and the supervisory system operation is described in detail. This installation illustrates that complete oilfield supervisory systems are both feasible and economical.

Introduction

Automation has now reached the stage of development such that highly sophisticated systems can be applied to most oilfield operations. The producing industry's interest has been sharpened in recent years by the serious cost-price squeeze that it is experiencing. Automation can materially reduce the cost of producing oil. A centralized system of supervision, control and data gathering, combined with tape programing for flexible scheduling, appeared to offer the most desirable answer to the requirements of automatic oilfield control in the Virginia Hills field. This system was installed in Nov., 1960, and is at present controlling 45 wells drilled on 160-acre spacing. The average depth of these wells is 9,300 ft. They are flowing wells with no water production. The Virginia Hills field (Fig. 1) is located in a remote section of Western Canada where the land is characterized by deep valleys, heavy timber and an abundance of muskeg (swamp). Before oil was discovered, no use was being made of the area and access was possible only in winter. A first-class road has now been built to the nearest highway 27-miles away, thereby reducing the distance to the nearest town to 50 miles. Because the staff required to operate this area would not be large enough to justify even the minimum of medical, educational and recreational facilities and because the cost of providing staff accommodations would be prohibitively high, a system of production control that could reduce the staff to a minimum was most desirable.

Field Layout and Equipment

A "satellite" system of facility layout usually results in the minimum investment per well and, thus, was used when planning the Virginia Hills field development. In a satellite system of production, many wells are produced through each central producing station (or battery), in this way the use of common equipment, such as line heaters, group separators, surge tanks, etc., is maximized and its cost per well is minimized. To offset the increased length of flow lines, remotely located satellite test stations are used for well testing and control. The total production from each satellite is transported through a common flow line to the central producing station. The area under control in the Virginia Hills field is divided into a number of sub-areas due to topography, accessibility and partnership interest.

JPT

P. 22^
Pressure Distributions in Eccentric Circular Systems
Authors: Temeng Kwaku O. , Horne Roland N.
Published: December 2007

This paper presents an analytical solution for the pressure transient response of a well producing from an arbitrary position within a circular drainage boundary. The analysis is performed for both constant pressure and no-flow outer boundary conditions. In the analysis of pressure effects in asymmetrical circular systems, the practice has been to represent the circular system by a square system for which solutions exist. While this representation yields adequate results for the cases of wells close to the center, this work shows that significant errors may arise in situations where the wells are close to the boundary. Dimen-sionless pressure drops are obtained by numerically inverting solutions in Laplace space and are plotted as functions of dimensionless time.

From the wellbore pressure behavior it can be inferred that an effect of the eccentricity of the system is an apparent reduction of the drainage radius. By introducing the concept of an "equivalent radius" in the constant pressure boundary case, we show that the eccentric system can be analyzed, for the most part, as if it were a symmetrical one. Shape factors are calculated and presented for various well locations. The shape factors show similarities to those for a square system for well positions close to the center but differ significantly for positions close to the boundaries.
Effects of Size on Three-Cone Bit Performance in Laboratory Drilled Shale
Authors: Black Alan D. , Tibbitts Gordon A. , Sandstrom John L. , DiBona Bennie G.
Published: December 2007

The effects of size on the performance of three-cone bits were measured during laboratory drilling tests in shale at simulated downhole conditions. Four Reed HP-SM three-cone bits with diameters of 612, 778, 912, and 11 in. [165, 200, 241, and 279 mm] were used to drill Man-cos shale with water-based mud. The tests were conducted at constant borehole pressure, two conditions of hydraulic horsepower per square inch of bit area, three conditions of rotary speed, and four conditions of weight-on-bit (WOB) per inch of bit diameter. The resulting rates of penetration (ROP's) and torques were measured. Statistical techniques were used to analyze the data.
Pressure Transient Analysis Methods for Bounded Naturally Fractured Reservoirs
Authors: Chen Chih-Cheng , Serra Kelsen , Reynolds Albert C. , Raghavan Rajagopal
Published: December 2007

New methods for analyzing drawdown and buildup pressure data obtained at a well located in an infinite, naturally fractured reservoir were presented recently. In this work, the analysis of both drawdown and buildup data in a bounded, naturally fractured reservoir is considered. For the bounded case, we show that five possible flow regimes may be exhibited by drawdown data. We delineate the conditions under which each of these five flow regimes exists and the information that can be obtained from each possible combination of flow regimes. Conditions under which semilog methods can be used to analyze buildup data are discussed for the bounded fractured reservoir case. New Matthews-Brons-Hazebroek (MBH) functions for computing the average reservoir pressure from buildup data are presented.
Case History of a Successful Flank Well Curtailment Program in a Peripheral Water Flood
Authors: Pierce Robert L. , Garrison William H.
Published: December 2007

This paper summarizes the waterflood performance of the KZWA subpool of the Upper Terminal zone, Fault Block VB, in the Wilmington oil field, Los Angeles County, Calif., following a major reduction in water withdrawals by shutting in flank wells. The program was initiated specifically to improve the net injection rate of the pool. Production and development history of the pool are discussed together with a review of secondary recovery operations. The pool was under gas injection for 7 1/2 years, followed by waterflood operations starting in May, 1958.Field two were run in an isolated area of the pool to establish performance that might he expected under the curtailment program. The paper includes projected economics to he expected under continuation of the program prior to the shut-in and the economics under the existing shut-in program. Criteria for selecting a water flood in which flank well curtailment is applicable are also discussed. The economics to date show that a saving in operating costs due to shutting in wells, and increased stimulation of oil from the net injectivity improvement have already increased operating profits.

Introduction

Determination of the optimum time to shut in flank producers in a peripheral water flood has long been a source of controversy among petroleum engineers. It is extremely difficult, even in the least complicated floods, to apply a strict set of rules to determine the economic limit of high-volume, high-watercut wells. The purpose of this study is to review a flank well shut-in program in the Upper Terminal VB zone in the Wilmington oil field, Calif. Only the KZWA subpool will be reviewed with respect to geology, reservoir data, development history, water injection history, and pool-wide flank- well curtailment program. The upper two sub-zones (HX and JY) were involved in the flank-well curtailment program, but to a lesser degree. However, examples of interference in individual wells producing from those subzones are reviewed and production from them, together with KZWA pool production, is analyzed. The predicted effect of a curtailment program on pool economics is reported along with the status of the analysis 1 1/2 years later.

Location, Geology and Reservoir Data

The Wilmington oil field is in the Wilmington and Harbor Districts of the city of Los Angeles and the Harbor District of the city of Long Beach, Los Angeles County, Calif. The location of the Wilmington oil field with respect to other fields in the Los Angeles Basin is shown in Fig 1.The oil-producing structure of the field is an anticlinal fold with its main axis trending in a northwesterly- southeasterly direction. The producing zones are highly faulted. There are six main fault blocks numbered I thru VI, and the large subfault blocks are designated by the suffix A, B and D. The fault block with which this study is concerned is VB. Fault Block V]3 is located in the eastern half of the presently developed area of the Wilmington oil field.

JPT
Distribution of Fluid Phases Within the Steam Zone in Steam-Injection Processes
Authors: Yortsos Yanis C.
Published: December 2007

The saturation distribution of steam, water, and oil within the steam zone in a steam-injection process at constant injection rates is examined. It is shown theoretically that for typical values of injection parameters the oil saturation in the steam zone rapidly reaches its residual value at steam zone conditions. This result, which corroborates previous experimental evidence, is a consequence of the relatively fast changes in phase saturations compared with the rate of the advance of the steam front. Explicit expressions for the steam saturation distribution are obtained. It is shown that the average steam saturation is a slightly decreasing function of time and approaches a limiting value that is a nearly constant fraction of the steam saturation at the injection point. This result provides theoretical justification for the assumption of constant average steam saturation in steam-injection calculations.
Modeling of Piled Foundations
Authors: Kriger Glenn A.
Published: December 2007

A comprehensive set of guidelines for constructing linear models of single piles and pile groups for foundations of offshore structures is presented. These models are used as boundary conditions at the base of the superstructure, thus permitting independent analysis of the superstructure from its supporting foundation.

This paper is a "how-to" text for piled foundation modeling. It is also of value to those in related disciplines, such as geotechnical specialists, who will gain insight into how their data is applied in analyzing structures supported by piled foundations. Discussions include the behavior and modeling of single piles and pile groups. Construction methods are presented for three types of pile models—matrix, springs, and equivalent pile. The advantages and disadvantages of each model type are described. Linear and nonlinear foundation behavior characteristics are treated in depth. Factors that influence the approach to a modeling problem are outlined. Emphasis is placed on providing the reader with an understanding of the physical behavior of piled foundations and model construction. A step-by-step procedure for model synthesis is provided in an example.
Minimization of Scale Deposits in Oil Wells by Placement of Phosphates in Producing Zones
Authors: Featherston Aleck B. , Mirham R. George , Waters A.B.
Published: December 2007

Deposition of compounds such as calcium carbonate, calcium sulfate and barium sulfate in formation flow channels, on tubing, casing and producing equipment has continuously plagued the oil industry. Although polyphosphates have a long history in scale inhibition, only relatively recently have the extremely slow solubility di-metallic polyphosphates been injected into producing zones in conjunction with fracturing.

As a result of such treatments, scale deposition in the formation in addition to the wellbore and producing equipment has been checked in some cases for over a year. Characteristics to be considered when selecting a phosphate for this type treatment have been outlined with the effect each has on scale prevention and on length of time they will be effective.

Introduction

Mineral deposition in formation flow channels, on tubing, casing and producing equipment has continuously plagued the oil industry. Compounds such as calcium carbonate, calcium sulfate and barium sulfate carried in the produced water may crystallize or precipitate as a result of a pressure drop, a temperature change or exceeding the solubility product. This scaling reduces and sometimes even stops oil production by plugging the formation, perforations or producing equipment.

Formation of scale on tubing and producing equipment has been recognized for many years. After extracting this equipment from the well, the deposits have been removed mechanically with scrapers and other such devices. Hydrochloric acid has been found effective when the plugging material is basically carbonate in nature.

As early as 1938 and 1939 Krynine and Yuster recognized that these scaling compounds frequently were deposited away from the wellbore in flow channels of waterflood wells. Acid, salts and phosphates were suggested as possible remedial treating chemicals. More recently work has been done which indicates water incompatible with the formation water sometimes can be used in water floods.
A Viscosity Correlation for Mixtures of Heavy Oil, Bitumen, and Petroleum Fractions
Authors: Shu W. R.
Published: December 2007

High viscosity is a major constraint in the recovery and transportation of heavy crudes and tar sand bitumens. Viscosity reduction may be achieved by mixing the crude with a light petroleum solvent. This paper presents a generalized correlation for calculating viscosities of such mixtures. A power-law mixing rule was generalized by use of the Einstein-type relationship for the viscosities of infinitely dilute solutions. Literature and in-house data were compiled to establish the correlation. The final correlation requires only density and viscosity of the two fluids to predict blending viscosity at any mixture composition. The correlation is tested with heavy-oil/solvent blending data and gives an excellent prediction of the blending viscosities.
The Effect of Thermoelastic Stresses on Injection Well Fracturing
Authors: Perkins T. K. , Gonzalez J. A.
Published: December 2007

When a cool fluid such as water is injected into a hot reservoir, a growing region of cooled rock is established around the injection well. The rock matrix within the cooled region contracts, and a thermoelastic stress field is induced around the well. For typical waterflooding of a moderately deep reservoir, horizontal earth stresses may be reduced by several hundred psi. If the injection pressure is too high or if suspended solids in the water plug the formation face at the perforations, the formation will be fractured hydraulically. As the fracture grows, the flow system evolves from an essentially circular geometry in the plan view to one characterized more nearly as elliptical.

This paper considers thermoelastic stresses that would result from cooled regions of fixed thickness and of elliptical cross section. The stresses for an infinitely thick reservoir have been deduced from information available in public literature. A numerical method has been developed to calculate thermoelastic stresses induced within elliptically shaped regions of finite thickness. Results of these two approaches were combined, and empirical equations were developed to give an approximate but convenient, explicit method for estimating induced stresses.

An example problem is given that shows how this theory can be applied to calculate the fracture lengths, bottomhole pressures (BHP's), and elliptical shapes of the flood front as the injection process progresses.
Flow Behavior of Foam: A Porous Micromodel Study
Authors: Owete Owete S. , Brigham William E.
Published: December 2007

The flow behavior of foam in porous micromodels has been studied visually by use of etched silicon wafers. Air was injected into homogeneous and heterogeneous porous media previously filled with an aqueous surfactant solution. The flow characteristics and the mobility of the injected air were determined under different conditions of pore dimensions, air injection rates, and surfactant concentrations.

In the experiments, air was found to be propagated by displacement of lamellae in long bubbles flowing and extending across several pore lengths, while the liquid flowed through the network of films. Propagation of foam bubbles formed at pore constrictions by snap-off was dominant in the heterogeneous model. Liquid and/or gas was trapped in some pores. The mechanisms observed depended on pore structure and surfactant concentration. A considerable reduction of effective air mobility was observed in the presence of foam. Mobility reduction depended on flow mechanisms.
Magnesium Oil Mud Provides Gauge Hole in Bischofite/Carnallite Formations
Authors: Carter T. S. , Smith J. E.
Published: December 2007

Laboratory tests conducted to investigate the possibility of using oil muds through the Zechstein formation of the Viking field showed that diesel-oil muds formulated with sodium- and/or calcium-type emulsifiers could break down if the wrong treatment was used to counteract contamination from the solubility of magnesium minerals. However, oil-mud samples prepared with magnesium compounds offered good mud stability and did not dissolve the contaminant. Therefore, this formulation was selected for a field test on a Viking well; this paper reviews the results. Drilling data from previous wells in the area are compared with values measured on the test well. Results indicate that the magnesium oil muds can provide a gauge hole in the bischofite/camallite zones that occur within the Zechstein formation.
Microscopic Observations of Solution Gas-Drive Behavior
Authors: Chatenever Alfred , Indra Mohit K. , Kyte John R.
Published: December 2007

Introduction

Microscopic mechanisms are critical in the behavior of reservoir systems and our knowledge of them uncovers pertinent factors made apparent in no other way. Mechanistic problems associated with evolution of solution gas have been considered by earlier investigators. Sage, Kennedy, Berry, and their co-workers have studied the number of bubbles formed in the evolution process. Van Meurs, has visually examined the patterns formed by the evolved gas in displacements in ideal packs. With enlargogram techniques Kimbler and Caudle have examined location of the points of genesis of free gas in unconsolidated sand packs.

In the present work 116 laboratory experiments were performed in a visual study of the solution gas-drive mechanism. Thin glass-bead packings and thin sections of natural sandstone and limestone were used as porous matrices in the experiments. As gas evolved the system was examined visually at different magnifications.

Certain differences in fluid behavior were observed for the different types of matrices. However, the findings of most interest were generally observed in all tests. These findings help clarify the roles of the physical parameters governing solution gas-drive behavior. They also provide a basis for further experimentation to help define this behavior in reservoir formations.

The experimental approach and techniques employed were developed by American Petroleum institute Research Project 47-B. Details of these are published in the literature. Observation flow cells were saturated with butane-saturated mineral oil at atmospheric pressure and drawn down to sub-atmospheric pressures to effect gas evolution.

Results of Gas Evolution Experiments

Gas Nucleation

In all the gas evolution experiments pressure had to be reduced to several psi less than atmospheric before the first point of gas nucleation appeared. This indicates that some degree of supersaturation must be reached before gas evolution will start. However, supersaturation behavior is variable and not precisely reproducible, even in identical systems.
In-Situ Leaching of Crownpoint, NM, Uranium Ore: Part 4—Laboratory Study of Strong Leaching Systems: Oxidant/Sulfuric Acid
Authors: Vogt Thomas C. , Strom E. Thomas , Johnson Warren F. , Venuto Paul B.
Published: December 2007

This paper presents laboratory data on the effectiveness of a severe leaching system, sulfuric acid (H2SO4) and an oxidant, in recovering uranium from refractory Crown-point uranium ore. A strong mineral acid, such as H2SO4, plus an oxidant, such as oxygen or hydrogen peroxide (H2O2), should be able to degrade the kerogen associated with uranium in slow-leaching uranium ores to expose the uranium mineral to leachate contact. Scoping-batch leach tests show that an H2SO4, ferric ion leachate gives good recoveries at a fast rate from Crown-point refractory ore. A composite core was fabricated with this refractory ore. A leachate of 0.5% H2SO4, 24.5 g/L Na2SO4, 1 g/L NaCl, and 0.2 g/L CO2 with 800 psig [5516 kPa] O2 gave 65% recovery of uranium from this core in about 30 PV's. This is almost double the recovery obtained from a similar core with a mild leaching system (O2/bicarbonate) in the same number of PV's. Plugging, which occurred twice during the leach run, appears to be related to movement of feldspar and quartz fines. Chemical consumption was fairly high in these H2SO4 experiments.
Single-Phase Fluid Flow in a Stratified Porous Medium With Crossflow
Authors: Cheng-Tai Gao
Published: December 2007

A new model is presented for a stratified reservoir. The model is used to study the influence of crossflow on pressure transient well tests and other single-phase flow problems. The reasons for single-phase crossflow in multilayer reservoirs are discussed. Solutions for linear and radial incompressible flow in a stratified reservoir with crossflow are presented; effects of reservoir parameters and crossflow on pressure are studied, and a criterion for considering crossflow between layers is suggested.
Scale Deposition in Surface and Subsurface Production Equipment in the Gulf of Suez
Authors: El-Hattab M.I.
Published: December 2007

Generally the deposition of oilfield scale in surface and subsurface production equipment can cause many operational problems. Scale precipitation in oilfields has a detrimental effect on fluids, processing equipment, pipelines, and downhole well equipment processing equipment, pipelines, and downhole well equipment as a result of Corrosion and flow restriction. Scale deposits in wellbores can result in severe production loss. Generally scale problems become more prevalent as oil and gas reserves are depleted and water production increases. production increases. Some of the Gulf of Suez oilfields, El Morgan, July, and Ramadan, have been waterflooded by the Gulf of Suez sea water. Compatibility tests have indicated probable deposition of scale on surface and probable deposition of scale on surface and subsurface production equipment. Case histories relating to scale deposition, removal and inhibition in surface equipment are discussed. The paper outlines the physical and theoretical prediction for downhole physical and theoretical prediction for downhole scale deposition in oil wells. The experience with scale removal and inhibition by the formation squeeze treatment technique is presented along with recommendations that can be applied to similar cases in other fields in the Gulf of Suez.

Introduction

The deposition of oilfield scale in surface and subsurface oil and gas production equipment has been recognized to be a major operational problem. The negative consequences of scale contribute to equipment wear and corrosion and flow restriction thus resulting in production decrease. Experience in the oil industry has indicated that many wells have suffered flow restrictions due to scale deposition within the formation, the well bore region, perforations, and tubing strings. Scale deposits in surface production equipment amplify these problems.

Oilfield scale costs much in terms of production losses, frequent pulling jobs, reperforations, redrilling and reaming, stimulation, and other similar remedial workovers. It is estimated that many wells in the U.S.A. have reduced production due to scale deposits in the formation and wellbore and that many oil producers and formations have been prematurely abandoned due to plugging by scale deposits. prematurely abandoned due to plugging by scale deposits. In the literature many case histories regarding the oilfield scale problem have been reported. Cowan et al have stated cases for calcium carbonate scale deposition in surface production equipment, in Mexico, South and West Texas, and North and South Louisiana oilfields.

P. 93
Stability of Displacement Fronts in Porous Media—Growth of Large Elliptical Fingers
Authors: Mui Kwoon C. , Miller Clarence A.
Published: December 2007

A theoretical analysis is presented for growth of a single, large elliptical finger in a porous medium. The objective is to obtain an understanding of how large fingers develop once a displacement front has become unstable. The results provide information beyond that available from linear analysis, which has been used in most previous work and applies only to infinitesimal perturbations.

Separate analyses are given for finger growth during instability of (1) the front accompanying displacement of one immiscible fluid by another, (2) the combustion front in a dry, forward combustion process, (3) a condensation front, and (4) the combustion front in dry, reverse combustion as employed in the linking step of underground coal gasification. In Cases 1 and 2, the fastest-growing finger is found so that growth rate and finger size can be estimated. In contrast, the linear analyses for these cases predict no fastest-growing disturbance. Thus, important additional information is provided by the elliptical finger model.

In Case 3, the condensation front, a fastest-growing disturbance is found as well. Results show that effects on stability of the mobility ratio and of the volume decrease accompanying condensation depend only on the shape of the finger (ratio of major and minor axes) while heat transfer effects also depend on the absolute size of the finger. Since the stabilizing effect of heat transfer is least for large fingers, such fingers are favored.

For Case 4, we found that the channel in underground coal gasification always advances at the maximum speed permitted by the reaction kinetics. Actual results confirm the basic validity of those obtained by Gunn and Krantz using linear analysis, but the elliptical finger model provides a clearer understanding of the physical phenomena controlling finger size and speed.
Wind Tunnel Tests of Inclined Circular Cylinders
Authors: Norton David J. , Heideman John C. , Mallard W. Wade
Published: December 2007

Forces on naturally roughened cylinders were measured for Reynolds numbers between 2×105 and 2×106 and inclinations of 0 to 40°. Results demonstrated the validity of the flow-independence principle in postcritical flow. Drag coefficients agreed with published values for artificially roughened cylinders. Strouhal numbers of about 0.21 were observed.
Approximate Solutions for Fractured Wells Producing Layered Reservoirs
Authors: Bennett Curtis O. , Camacho-V. Rodolfo G. , Reynolds A. C. , Raghavan Rajagopal
Published: December 2007

New analytical solutions for the response at a well intercepting a layered reservoir are derived. The well is assumed to produce at a constant rate or a constant pressure. We examine reservoir systems without in-terlayer communication and document the usefulness of these solutions, which enable us to obtain increased physical understanding of the performance of fractured wells in layered reservoirs. The influence of vertical variations in fracture conductivity is also considered. Example applications of the approximations derived here are also presented.
Fluid Flow in Cracks as Related to Low-Permeability Gas Sands
Authors: Brower K. R. , Morrow N. R.
Published: December 2007

A problem in formation evaluation of tight gas sands is that their permeabilities are sometimes surprisingly sensitive to variations in overburden pressure. Photomicrographs of pore casts show an interconnected system of sheet pores, which are somewhat like the surfaces of a randomized honeycomb. A mathematical relation for predicting the pressure dependence of flow rate in sheet pores has been derived from the dimensions of the pores and the elastic constants of the matrix. The equation has been validated by measurements on artificial media containing cracks of known dimensions in glass and concrete. The observed pressure sensitivity of the gas sands used in this study requires the aspect ratio of the pores (in this case, the ratio of average large dimensions to sheet thickness) to be greater than 100. Aspect ratios have been determined by taking the large dimension from photomicrographs of pore casts or grain size and the thickness from mercury injection pressure or the slope of a plot of apparent permeability vs. the reciprocal of mean gas pressure. The latter gives the diffusive contribution to gas flow from which the pore size can be calculated. The two methods for measuring pore size give satisfactory agreement. The aspect ratios for the sheet pores in tight gas sands are large enough to explain the dependence of permeability on overburden pressure.
Measurement of Width and Pressure in a Propagating Hydraulic Fracture
Authors: Warpinski N. R.
Published: December 2007

Measurements of width and pressure in a propagating hydraulic fracture have been made in tests conducted at the U.S. DOE's Nevada test site. This was accomplished by creating an "instrumented fracture" at a tunnel complex (at a depth of 1,400 ft [425 m]) where realistic in-situ conditions prevail, particularly with respect to stress and geologic features such as natural fractures and material anisotropy.

Analyses of these data show that the pressure drop along the fracture length is much larger than predicted by viscous theory, which currently is used in models. This apparently is caused by the tortuosity of the fracture path, multiple fracture strands, roughness, and sharp turns (corners) in the flow path resulting from natural fractures and rock property variations. It suggests that fracture design models need to be updated to include a more realistic friction factor so that fracture lengths are not overestimated.
The Selection of a Multiple Completion Hook-Up
Authors: Althouse W.S. , Fisher H.H.
Published: December 2007

The reasoning behind the inception, rate of development and successful application of current dual, triple and quadruple completions is highly economic in character. Selection of a practical multiple completion hook-up therefore must necessarily involve strong economic considerations. Type and subsequent cost of any multiple completion hook-up is directly related to number of zones to be produced and workover and artificial-lift requirements of each zone. An analysis of available subsurface equipment that makes the modern multiple completion practical in the light of design, advantages and limitations provides a base for selection of components. A systematic presentation of multiple completion hook-ups from the simplest, most inexpensive two-zone completion to the most complex four-zone completion, in order of increasing cost and flexibility provides a graphic systematic base for selection of a practical multiple completion hook-up.

Introduction

Advancement in multiple zone techniques and equipment has been so rapid in recent years that it becomes difficult even for those who specialize in this field not only to keep up with it, but to maintain an over-all perspective. Hardly a month goes by that a trade publication does not present a new dual, triple or quadruple completion method. Many of these articles not only imply widespread acceptance of the particular method but strongly suggest that previous methods are shortly doomed for obsolescence. The facts are that there are many areas, perhaps an overwhelming majority, where the complex dual, triple or quadruple completion would not be economically feasible.

Operators in these areas are confronted with the problem of selecting not only a practical multiple completion hook-up but one that is economical as well. In order to make this selection they should have as broad a view of all multiple completion techniques and equipment as possible and some sort of systematic method of evaluating each method in light of any given set of conditions. The systematic basis for this selection in our opinion involves(1) number of zones to be produced; (2) flowing, artificial-lift and workover requirements of each zone; (3) general knowledge of various types of subsurface equipment and its limitations; and (4)general knowledge of possible remedial operations that can be performed with certain fundamental hook-ups.
A General Purpose Thermal Model
Authors: Rubin Barry , Buchanan W. Lloyd
Published: December 2007

This paper describes a fully implicit four-phase (oil, water, gas, solid fuel) numerical reservoir model for simulating hot water injection, steam injection, dry combustion, and wet combustion in one, two, or three dimensions and in either a Cartesian, radial, or curvilinear geometry. The simulator rigorously models fluid flow, heat transfer (convective and conductive), heat loss to formation, fluid vaporization/condensation, and chemical reactions. Any number of oil or gas phase components may be specified, along with any number of solid phase components (fuel and catalysts).

The simulator employs either D4 Gaussian elimination or powerful incomplete factorization methods to solve the often poorly conditioned matrix problems. An implicit well model is coupled to the simulator, where reservoir unknowns and well block pressures are primary variables.

This paper includes (1) comparisons of the numerical model's results with previously reported laboratory physical models' results for steam and combustion and (2) analytical solutions to a hot waterflood problem. In addition, an actual field-scale history match is presented for a single-well steam stimulation problem.
Influence of Interfacial Tension on Gas/Oil Relative Permeability in a Gas-Condensate System
Authors: Asar Hamza , Handy Lyman L.
Published: December 2007

To understand better the effect of interfacial tensions (IFT's) on gas/oil relative permeabilities, with particular emphasis on those effective in condensate reservoirs, an experimental procedure was developed and used with the highly volatile methane/propane system. The objective was to measure steady-state relative permeabilities as functions of IFT. Thus the IFT was varied from 0.03 to 0.82 dynes/cm [0.03 to 0.82 mN/m], corresponding to pressures near the critical at a constant temperature of 70°F [21°C].

Individual relative permeability curves obtained as a function of gas saturation approach the 45° [0.79-rad] diagonals for both gas and oil as the IFT is lowered. This supports the expectation that relative permeability curves for both gas and oil become straight lines as the IFT approaches zero. At the highest IFT for which experiments were performed (0.82 dynes/cm [0.82 mN/m]), the relative permeability curves approached those obtained for a nitrogen/kerosene flood for which the IFT is approximately 30 dynes/cm [30 mN/m].

The most important conclusions derived from this work are that (1) the curvatures of the relative permeability curves diminish as the IFT is reduced, (2) the irreducible gas and liquid saturations approach zero as the IFT approaches zero, and (3) relative gas/oil permeabilities for gas-condensate reservoirs are altered from the normal relative permeabilities only at pressures, temperatures, and compositions close to the critical point.
Ethoxylated Oleyl Sulfonates as Model Compounds for Enhanced Oil Recovery
Authors: Carmona Irene , Schechter R. S. , Wade W. H. , Weerasooriya Upali
Published: December 2007

Precisely ethoxylated oleyl sulfonates were prepared and studied as model surfactant candidates for EOR. They were found to yield low interfacial tensions (IFT's), to give high solubilization parameters, and to have high electrolyte tolerance. Unfortunately, as a class of compounds they have a tendency to form liquid crystals (rather than microemulsions), which must be overcome by adding cosolvents, elevating temperatures, or restricting the maximally ethoxylated species.
Direct Thickeners for Mobility Control of CO2 Floods
Authors: Heller J. P. , Dandge D. K. , Card R. J. , Donaruma L. G.
Published: December 2007

This paper describes efforts in an experimental search for polymers that are sufficiently soluble in dense CO2 that they could serve as mobility control agents. The operation of the apparatus designed and built for the measurement of solubility in condensed gases is described. A modified version of this apparatus has been used to measure viscosity by timing the fall of a cylinder in a tube.

More than a dozen polymers have been found that are soluble at least in the parts-per-thousand (ppt) range in liquid and in dense supercritical CO2. As pressures and temperatures are varied, the solubilities of these polymers generally are found to increase with increasing CO2 density. Certain generalizations have been made concerning the influence of various polymer properties on their solubility in dense CO2. These properties include structure, stereochemistry, and molecular weight. Although the viscosity enhancements of the solutions measured thus far are insufficient for purposes of mobility control, they provide clues that point toward those features of polymer molecules that yield greater thickening properties.

Also discussed are considerations involved in the application of direct thickeners in the mobility control of CO2 floods and the advantages in the use of such CO2-soluble polymers in place of methods that involve the injection of water.
Pressure Inversion and Material Balance Calculations
Authors: Mead Homer N.
Published: December 2007

In a reservoir when gas comes out of solution and rises, additional pressure is created because of the change in position of this gas in the bounded volume. If this pressure effect is not taken into account as a pseudo-influx in material balance calculations on reservoirs in which there is evolving gas, an error is introduced that is directly proportional to the length of oil column and amount of gas evolved and inversely proportional to the reservoir pressure. In reservoirs with small oil column this pseudo-influx is of little importance. The larger the oil column the more important the effect becomes. The most important application, however, will be for reservoirs with declining pressure in which increasing water entry has been indicated by material balance calculations. It could be that this indication is the result of the cited pseudo-influx and not water entry at all. This paper attempts to explain this phenomenon in relation to material balance calculations and presents an approximate method of determining the pseudo-influx.

Introduction

Only recently has the pressure-volume relationship of gas rising in a liquid appeared in engineering literature, although its effect has been discussed for several years-especially among engineers engaged in drilling operations. The writer published a paper in 1957 in which this phenomenon was examined in relation to blowouts in drilling wells. Also, in 1957 Stegemeier and Matthews authored a paper in which the relationship was presented with respect to pressure build-up tests when shutting in producing wells. In this paper the effect will be called "pressure inversion" which is descriptive of the phenomenon.

Fundamentally, the effect just mentioned is the result of changing the position of a quantity of energy contained within the gas itself (as a result of its compression) within the bounded volume in which the gas exists. If the gas were allowed to expand "beyond all bounds" there could be no pressure inversion effect. This is because all of the energy contained within the gas as a result of compression would have been released.