bluuebunny/crossref_metadata_2025 huggingface dataset:
Experimental Study of the Gelation Behavior of a Polyacrylamide/Aluminum Citrate Colloidal-Dispersion Gel System
Authors: Ranganathan Raja , Lewis Robert , McCool C. S. , Green D. W. , Willhite G. P.
Published: December 2007

The gelation behavior of a polyacrylamide/aluminum citrate colloidal-dispersion gel (CDG) system was investigated in sandpacks at frontal advance rates of 2 ft/D. A gelatinous mass formed where the gelant encountered a change in flow medium. Permeabilities of homogeneous media were reduced only by factors that were similar to those obtained with a polymer displacement alone.

A laboratory investigation of a polyacrylamide/aluminum citrate CDG system was conducted to determine whether the system develops in-depth permeability modification in unconsolidated sandpacks. The study includes flow of the polymer and in-situ gelation behavior of the gelant in porous media and aggregate growth during the gelation reaction in beakers.

Flow experiments were conducted in long unconsolidated sandpacks in which the gel solution was mixed in-line before injection. Injection rates were designed to provide adequate residence time for the gel solution to develop in-situ flow resistance during displacements based on bulk gel characterization tests. Residual resistance factors were determined following a static rest period in which the sandpack was left saturated with the injected gel solution. For comparison, apparent viscosity and residual resistance factors were also determined for the polymer flowing through unconsolidated sandpacks. Membrane dialysis was used to study the aggregate size distribution of the gel system at selected times after mixing.

In-depth in-situ flow resistance did not develop when the gelling solution was injected into the sandpacks at frontal advance rates of 2 ft/D. Propagation through the sandpack was similar to a polymer solution. Flow resistance was characterized by the formation of a gelatinous filter cake, which formed when the injected solution encountered a change in flow medium, such as a screen placed at the ends to retain sand in place, the interface between the 50-mesh coarse sand layer at the inlet and the rest of the sandpack, and void spaces. Delaying injection by 2 hours after mixing in-line (to simulate field conditions) resulted in severe front-end stripping of gel aggregates. In all cases, residual resistance factors for the gel solution were similar to those obtained with a polymer displacement alone. Effluent fractions from gel solution displacements never developed a gel structure, and their viscosities were significantly lower than the injected solution. In the study of gel size distribution, aggregates were not detected at reaction times of 4 and 8 hours.
How Permeability Depends on Stress and Pore Pressure in Coalbeds: A New Model
Authors: Palmer Ian , Mansoori John
Published: December 2007

In naturally fractured formations such as coal, permeability is sensitive to changes in stress or pore pressure (i.e., changes in effective stress). This paper presents a new theoretical model for calculating pore volume (PV) compressibility and permeability in coals as a function of effective stress and matrix shrinkage, by means of a single equation. The equation is appropriate for uniaxial strain conditions, as expected in a reservoir. The model predicts how permeability changes as pressure is decreased (i.e., drawdown). PV compressibility is derived in this theory from fundamental reservoir parameters. It is not constant, as often assumed. PV compressibility is high in coals because porosity is so small. A rebound in permeability can occur at lower drawdown pressures for the highest modulus and matrix shrinkage values. We have also history matched rates from a boomer well in the fairway of the San Juan basin by use of various stress-dependent permeability functions. The best fit stress/permeability function is then compared with the new theory.
Conditioning of Pacific Ocean Water for Waterflood Injection
Authors: Sudbury J.D. , Knutson C.F. , Felsenthal Martin , Lung J.D.
Published: December 2007

This paper has been written to summarize the laboratory and field studies leading to injection of Pacific Ocean water into the Third Grubb formation.

Laboratory tests for studying the permeabilities of cores to Pacific Ocean water are described. Results of these tests showed that the water could be successfully injected if it is chemically stable, sterile, and properly filtered. Clay swelling was shown to be a comparatively minor factor in permeability reduction.

Studies leading to development of an economical system for properly conditioning the ocean water are discussed. It was necessary to control pH, calcium carbonate deposition, bacterial growth, iron solubility, oxygen, and suspended solids. A relatively simple system combining the use of sulfur dioxide, a quaternary ammonium chloride, and filtration was shown to adequately control all these factors. This combination has not previously been used as a water treating technique.

Evaluation tests of the water conditioning system prior to injection are described, and results of such tests are presented. Control measures needed to insure a continuously adequate water treatment are reviewed.

Introduction

The utilization of sea water for waterflooding has only recently been attempted. Knowledge of treating requirements has been limited, and in most cases no water treating has been done.

Prior to the initiation of the Third Grubb zone pilot water flood at Ventura, Calif., extensive laboratory research was done in an effort to define the treatment necessary to provide a suitable injection fluid.

Close coordination and cooperation between field and research personnel were found to be the foremost requisites in developing the most economical and practical method for treating ocean water.

Laboratory Studies

Plugging Tendencies of Untreated Ocean Water

A program of laboratory studies was initiated for the purpose of evaluating whether ocean water could be injected into the formation for prolonged periods of time without causing plugging of the pore spaces of the formation. Because of the fairly low permeability of the formation (averaging about 40 md), it was realized from the outset that a water of exceptionally high quality was needed.
Addressing BHA Whirl: The Culprit in Mobile Bay
Authors: Mason J. S. , Sprawls B. M.
Published: December 2007

Lateral bottomhole assembly (BHA) vibration, more particularly BHA whirl, is known to be an extremely destructive downhole phenomenon, the occurrence of which is thought to be one of the primary contributing factors to drillstring failure in Mobile Bay. Unfortunately, indications that BHA whirl is occurring while drilling are rarely evident from conventional surface measurements, especially in deeper sections of wells. Without knowledge of the existence of a problem, avoidance is almost impossible.

For the first time, the potential for the surface identification of BHA whirl is thought to be possible through the measurement of drillstring vibrations. We present data from a well in Mobile Bay where surface vibration measurement and monitoring was conducted while drilling the 12¼-in. hole section.

Axial and torsional data demonstrate characteristics thought to be indicative of BHA whirl, which is shown to be associated with accelerated drillstring fatigue, as demonstrated by BHA failures. Various approaches were taken to eliminate the whirl once the phenomenon was recognized, with ultimate success in that the incidence of BHA failure was reduced. Prewell planning and improved drilling practices resulted in the use of fewer bits and reduced drilling time over the same section on wells previously drilled in the area.
Underbalanced Drilling: Praises and Perils
Authors: Bennion D. B. , Thomas F. B. , Bietz R. F. , Bennion D. W.
Published: December 2007

Underbalanced drilling (UBD) has been used with increasing frequency to minimize problems associated with invasive formation damage, which often greatly reduce the productivity of oil and gas reservoirs, particularly in openhole horizontal well applications. UBD, when properly designed and executed, minimizes or eliminates problems associated with the invasion of particulate matter into the formation as well as a multitude of other problems such as adverse clay reactions, phase trapping, precipitation, and emulsification, which can be caused by the invasion of incompatible mud filtrates in an overbalanced condition. In many UBD operations, additional benefits are seen because of a reduction in drilling time, greater rates of penetration, increased bit life, a rapid indication of productive reservoir zones, and the potential for dynamic flow testing while drilling.

UBD is not a solution for all formation damage problems. Damage caused by poorly designed and/or executed UBD programs can rival or even greatly exceed that which may occur with a well-designed conventional overbalanced drilling program. Potential downsides and damage mechanisms associated with UBD will be discussed. These include the following.

Increased cost and safety concerns. Difficulty in maintaining a continuously underbalanced condition. Spontaneous imbibition and countercurrent imbibition effects. Glazing, mashing, and mechanically induced wellbore damage. Macroporosity gravity-induced invasion. Difficulty of application in zones of extreme pressure and permeability. Political/career risk associated with championing a new and potentially risky technology. We discuss reservoir parameters required to design an effective underbalanced or overbalanced drilling program, laboratory screening procedures to ascertain the effectiveness of UBD in a specific application and review the types of reservoirs that often present good applications for UBD technology.
Characterization and Prevention of Formation Damage During Horizontal Drilling.
Authors: Yan Jienian , Jiang Guancheng , Wang Fuhua , Fan Weiqing , Su Changming
Published: December 2007

The effect of various factors on the productivity of horizontal wells was quantitatively analyzed. The results show that formation damage is an important factor affecting productivity for the low-permeable sandstone formations studied. The effect of formation damage for a horizontal well on production rate is consistently much higher than that for a vertical well drilled in the same formation. The design criteria, formulations, properties, and applications of three low-damaging drilling muds were discussed. It was observed that the three fluids provided excellent formation protection with much lower skin factors and much larger percentages of regained permeability as compared with other commonly used drilling muds. The oil production rates of most horizontal wells are three to five times higher than that of their adjacent vertical wells, which is highly related to the effective prevention of formation damage.
Development of a Commercial Wireline Retrievable Coring System
Authors: Warren Tommy , Powers Jim , Bode David , Carré Eric , Smith Lee
Published: December 2007

A wireline retrievable coring system for use with conventional drilling equipment is described. The coring system was developed and tested for application in evaluating coalbed methane prospects where a large quantity of core is required, and it is essential that the core is processed soon after it is cut. A drill plug allows for alternation between coring and drilling without tripping the drill-string. The system is particularly advantageous for coring long intervals, multiple zones relatively close together, or when the exact target depth is unknown. The system has been used to core more than 4940 m (15,057 ft) in Poland, Germany, and France, with a combined core recovery of 94%. In addition, the impact of varying rig costs on total savings is factored into the overall economic evaluation of the system.
Structure H Hydrates: Implications for the Petroleum Industry
Authors: Mehta A. P. , Sloan E. D.
Published: December 2007

Structure H (sH) hydrates are unique since their formation requires both a light gas such as methane and molecules typically present in oil and condensates. Several sH formers such as methylcyclopentane, methylcyclohexane, neohexane, and adamantane, are indigenous to petroleum. Phase equilibrium measurements indicate that the temperature and pressure conditions under which sH hydrates form as a stable phase are consistent with those in hydrocarbon production, processing, and transportation facilities. The stable occurrence of sH hydrates calls into question existing hydrate prediction programs and suggests that the hydrate phase itself should be measured, in contrast to previous experimental practice. In this work, we provide a brief overview of the current state-of-the-art on sH hydrates, with an emphasis on its implications for the petroleum industry.
Application of the Gelatin Model for Studying Mobility Ratio Effects
Authors: Burton Melvin B. , Crawford Paul B.
Published: December 2007

A procedure is given which describes how the gelatin model may be used to study the effect of mobility ratio on areas swept before and after breakthrough in fluid injection programs. Differences in mobility ratio are achieved through the proper selection of electrolytes for the invading and displaced fluids. The progress of the front is followed visually and photographed or traced onto plates as desired positions before and after breakthrough. Example applications to standard flooding patterns, vertically and horizontally fractured reservoirs and the in-situ combustion recovery process are presented.

Introduction

In water flooding, gas cycling and other fluid injection programs, the sweep efficiencies and swept areas after breakthrough are known to depend on the mobility ratio. Previous investigators have described the application of the X-ray technique, stepwise use of the potentiometric model and numerical procedures for studying these problems. Others have described the application of the electrolytic and gelatin models for studying sweep efficiencies at a mobility ratio near one. It is a purpose of this paper to describe a procedure for using the gelatin model to study swept areas at mobility ratios other than one.

Procedure

The technique developed for gelatin model studies is composed of four phases: the construction of the model, the selection and preparation of electrolytes, the running procedure, and the recording of the swept areas. Each phase is discussed independently in order that the over-all procedure will not be confused.

Construction of the Model

Since some of the advantages of the gelatin model are its economy, and speed, it is desirable to have as small a model as is possible without creating error through the inability to follow visually the progress of the colored front. For this work, it was found that a distance of 4 to 6 cm between salt bridges is convenient to use. Since the size is relatively small, it follows that the gelatin layer must be thin. For this study, 1/8 in. was used as the gelatin thickness in each case.
Miscible Displacement in a Multiphase System
Authors: Thomas Gene H. , Countryman Gary R. , Fatt Irving
Published: December 2007

Introduction

Displacement by flooding with a miscible liquid is a possible means for recovering the estimated two-thirds of the oil that remains behind after primary production. The immense economic importance of a process that can recover such large quantities of oil has led to extensive laboratory studies of miscible displacement. As usual in production research, most laboratory studies of miscible displacement have not attempted to reproduce all of the conditions existing in a petroleum reservoir. In the early stages of investigation the need has been for information on the broad, basic principles of the phenomena involved in miscible displacement. The effects of overburden pressure, reservoir temperature, and wettability have been considered of secondary importance. However, one property of a petroleum reservoir which is expected to be of major importance and yet has been omitted from many laboratory studies is the presence of interstitial water.Two possible effects of interstitial water on the displacement mechanism in the hydrocarbon phase immediately come to mind. First, from the generally accepted theory that capillarity governs the distribution of oil and water in porous rock one would expect that for water-wet rock the water will be in the small pores and oil in the large pores. A miscible displacement of oil carried out in the presence of water is operating in a pore size distribution shown in Fig. 1b, whereas if the same test had been performed with only one phase present the pore size distribution is as shown in Fig. la. Although there is not yet a theory of miscible displacement which explains in detail the effect of pore size distribution, one would expect the differences between Figs. 1a and 1b to influence the displacement efficiency.A second factor which may make a multiphase system different from a single-phase system is the presence in the multiphase system of dead-end pores or dendritic structure. Experiments of various kinds on reservoir rock have led to the belief that all pores in the network structure of a porous rock take part in conducting fluid during single phase fluid flow. There are then no dead-end pores and no fingers or dendritic structures containing stagnant fluid.

SPEJ

P. 189^
A New Mathematical Model for Oil/Water Separation in Pipes and Tanks
Authors: Hafskjold Bjørn , Celius H. K. , Aamo O. M.
Published: December 2007

In top-side processing, it is observed that the separation rate for water in oil systems increases with the increase in the water cut, and that some water remains in the oil even after long settling times. These features may be qualitatively understood by a combination of coalescence and settling. This work describes a mathematical-numerical model that describes these mechanisms quantitatively. Based on input about system dimensions, flow rate, fluid physical properties, fluid quality and drop size distribution at the inlet, it calculates the quality of the output oil. The model was validated by laboratory experiments and field data.
Development and Testing of a Foam-Gel Technology to Improve Conformance of the Rangely CO2 Flood
Authors: Friedmann F. , Hughes T. L. , Smith M. E. , Hild G. P. , Wilson A. , Davies S. N.
Published: December 2007

Thirty-six thousand four hundred barrels of CO2 gelled foam were successfully placed via an injector well into the Rangely Weber Sand Unit in Colorado. The treatment objectives were (1) to improve volumetric conformance in this CO2 flood by reducing excessive CO2 breakthrough through fractures, and (2) to increase oil recovery from the associated producers. Local reservoir characteristics indicate the need for a large-volume treatment to achieve these goals. The required treatment volume is beyond the economic limits of standard gel systems. Foam gel technology is one way to economically achieve in-depth conformance improvement at Rangely by replacing 60 to 80% of the liquid phase by the less expensive CO2 phase. A gelled foam system was specifically designed for application to Rangely conformance problems. The field-tested surfactant/gel system was designed according to the following criteria: (1) to produce strong and robust gelled foams under the harsh pH conditions of a CO2 flood, (2) to provide enough gelation delay to achieve the injection of a large foam volume with manageable injectivity reduction, and (3) to considerably reduce the unit cost of the treatment fluid relative to standard non-foamed gel systems. This paper describes the methodology used to design and test the optimum gelled foam system for Rangely. Laboratory results are presented to support the chemicals system selection, including gelation kinetics experiments, surfactant selection, and corefloods with supercritical CO2 at field conditions. The candidate well selection process is described, including injection profile surveys, offset well response, and bypassed reserves calculation. Data taken during the injection phase of the program, including injectivity history and on-site quality control monitoring of the chemical system behavior, are given. Finally a preliminary assessment of the impact of the treatment on CO2 cycling rates and incremental oil production is presented.
Systematic Study of Iron Control Chemicals Used During Well Stimulation
Authors: Taylor K. C. , Nasr-El-Din H. A. , Al-Alawi M. J.
Published: December 2007

A new type of experimental procedure was developed to study iron control chemicals in acidizing treatments (citric acid, nitrilo-triacetic acid, and acetic acid) at temperatures from 25 to 95°C. This procedure gives plots of iron in solution versus equilibrium pH, while previous work has generally studied iron concentration in completely spent acid solutions. Hydrochloric acid concentrations of 7.5 to 28 wt %, sodium chloride concentrations of 0 and 5 wt%, and iron (III) concentrations from 1000 to 10 000 mg/kg were examined with varying concentrations of commonly used iron control chemicals. A systematic study of this kind has not previously been reported in the literature. The following new results were found:

Iron (III) hydroxide precipitated from spent acid at much lower values of pH than are generally believed in the literature. The general belief is that iron (III) hydroxide precipitation begins at a pH of about 2.2 and is complete at a pH of 3.3. From experimental results, precipitation begins at pH values of about 1 and is nearly complete by pH 2 at 25°C. As the temperature was increased, iron (III) became significantly less soluble in the spent acid. This means that iron (III) hydroxide precipitation is potentially more damaging to the formation than generally believed. Time-dependent iron precipitation can occur in the absence of iron control chemicals. Time-dependent precipitation of ferric/calcium complexes with nitrilotriacetic acid (NTA) and citric acid was found. In partially spent acid, precipitation of previously unreported complexes containing an iron/calcium/chelating agent in a 1/1/1 mole ratio was observed. This behavior is important because of potential formation damage during the acidizing treatment itself, or during shut-in of the well after stimulation. Synergism with citric acid/acetic acid mixtures was found. These two iron control chemicals were able to prevent iron precipitation better in combination than individually.
Stress Magnitudes from Logs: Effects of Tectonic Strains and Temperature
Authors: Blanton T. L. , Olson J. E.
Published: December 2007

An improved method of calibrating in-situ stress logs was validated with data from two wells. Horizontal stress profiles are useful for hydraulic fracture design, wellbore stability analysis, and sand production prediction. The industry-standard method of estimating stresses from logs is based on overburden, Poisson's ratio, and pore pressure effects and gives an estimate of minimum horizontal stress. The model proposed here adds effects of temperature and tectonics and outputs of minimum and maximum horizontal stress magnitudes, which are particularly important to the successful completion of horizontal and deviated wells. This method was validated using data collected from a GRI research well and a Mobil well. Seven microfrac stress tests in GRI's Canyon Gas Sands Well of Sutton County, Texas, provided a means of comparing the predictive capability of different methods. First, one of the seven stress tests was selected as a calibration standard for the stress log. Then the results obtained from the two calibration methods were compared to stress magnitudes from the other six stress tests. This process was repeated using each of the seven stress tests as a calibration standard and comparing predictions to the other six. In every case, the method incorporating tectonic strain and thermal effects produced significantly more accurate values. The Mobil well is located in the Lost Hills Field in California, and pre-frac treatment breakdown tests were used to calibrate a log-derived stress profile. All of the data were used simultaneously to get a best fit for the log-derived stress. The log and its fracture height growth implications compared favorably with available fracture diagnostic data, and maximum horizontal stress values were consistent with published values for a similar, nearby reservoir.
Modeling High-Angle Wells in Laminated Pay Reservoirs
Authors: Fair Phillip S. , Kikani Jitendra , White Christopher D.
Published: December 2007

Productivity improvement and acceleration projects have gained substantially from the success of horizontal well drilling technology. Successful placement of near-horizontal wells in difficult reservoir configurations has become routine. However, not all reservoir situations are amenable to horizontal drilling. Specifically, laminated reservoirs such as thinly bedded turbidites in the Gulf of Mexico (GOM) have been perceived as poor targets. Potentially large reserves are locked in these reservoirs. These laminated turbidite systems have near-zero vertical permeability at the Bouma sequence1 scale and extremely small kv/kh ratios (kv/kh≈0) at the full field, reservoir simulation grid-block scale.

In general, a low well count helps minimize development costs. Highly deviated wells (80°≤ θw<90°) cutting the entire sand package may make it possible to obtain both high field production rates and low well counts. Slanted wells have been known to improve productivity of wells with kv/kh≈0. However, the slanted well model given by Cinco2,3 does not predict any improvement in well productivity for such wells. This apparent paradox is reconciled in this paper.

Bed thickness, well diameter, and well angle determine the geometric pseudoskin of these thin-bedded sequences. For wells that are nearly horizontal, a simple technique is introduced to calculate the geometric skin without complex modeling. The range of validity of this approximation was determined by comparison with fine-grid simulations.
CT Imaging of Wormhole Growth Under Solution-Gas Drive
Authors: Tremblay Bernard , Sedgwick George , Vu Don
Published: December 2007

The cold production process has increased primary heavy oil production and has been applied with commercial success in the Lloydminster area (Alberta, Canada). In this process, the production of sand is encouraged in order to form high permeability channels (wormholes) within the formation. The process depends on the formation and flow of foamy oil into the wormholes as these grow away from the wellbore and into the reservoir. The formation and growth of a wormhole was visualized using a computed tomography scanner, in an experiment in which oil flowed through a horizontal sandpack and out an orifice. The only drive mechanism was the formation and expansion of methane bubbles within the live oil. The pressure gradient at the tip of the wormhole was approximately 1 MPa/m when it started to develop at the orifice. Two conditions appear necessary for wormholes to keep growing: (1) the pressure gradient at the tip of the wormhole must be sufficiently large to dislodge the sand grains, (2) the pressure gradient along the wormhole must be large enough to transport the sand from the tip to the orifice. The pressure gradient at the tip of the wormhole was 2.9 MPa/m when it reached its maximum length. This suggests that, although the pressure gradient at the tip was sufficient for erosion to occur, the sand could not be carried along the wormhole causing the wormhole to stop growing. The pressure depletion experiment suggests that wormholes can easily develop in uncemented sand in the field since the maximum oil production rate during wormhole growth (18 cm3/day) was significantly lower than in the field. The minimum pressure gradient (11 kPa/m) necessary for sand transport along the wormhole is important in calculating the extent of wormhole growth in the field.
A New Approach To Evaluate Layer Productivity Before Well Completion
Authors: Prat Giovanni Da , Colo Carlos , Martinez Ramon , Cardinali Guillermo , Conforto Gustavo
Published: December 2007

This work presents a new methodology to identify fluid in formation layers and estimate individual reservoir parameters using openhole formation testing techniques. Real-time pressure and fluid identification data are obtained from a new wireline formation testing tool. The tool's dual packer module is needed to isolate individual zones. Field cases from wells located in the San Jorge Gulf basin and in the Neuquen basin illustrate the validity of testing methodology. The reservoir permeability (vertical and horizontal) and formation damage are calculated from pressure transient analysis of buildup and interference pressure data taken from several wells. The results obtained using this technique is consistent with those obtained from testing after well completion (cased hole drillstem test). Evaluation results can be used to decide whether to complete or abandon the tested zone. Fluid type is identified in real time using an optical fluid analyzer. Evaluation of anisotropy on a productive zone scale from the vertical interference test is presented.
Evaluation of Dynamic Pseudofunctions for Reservoir Simulation
Authors: Guzmán R. E. , Giordano Domenico , Fayers F. J. , Godi Antonella , Aziz Khalid
Published: December 2007

We present a detailed investigation on the reliability of some of the dynamic pseudofunctions used to upscale flow properties in reservoir simulation. A one-dimensional example (1D) and a real field application are used to evaluate methods developed by Kyte and Berry and Stone, and a new flux weighted potential (FWP) method. A derivation of Stone's method (based on the description given by Stone above) is presented, which is found to give an inconsistent set of equations. Stone's analytical example was used to illustrate how pseudorelative permeabilities that exhibit non-physical behavior may still give acceptable results, but this success can disappear with changes in boundary conditions. The pseudofunctions from a field application were not able to match the 2D simulations from which they were calculated, even when a different pseudofunction was used for each coarse grid block. Improvements were obtained when directional pseudofunctions were used, but still the results were not satisfactory. Similar results were found when comparing fine and coarse grid 3D simulations for a quarter of a five-spot pattern in this field. The results presented in this article suggest that dynamic pseudofunctions, as applied here and as commonly used in industry, may not be an adequate approach to up-scaling. The possibility of large errors and the difficulty in predicting when they may occur make the use of pseudofunctions examined in this paper unreliable.
Aquifer Behavior During Brent Depressurization and the Impact on Neighboring Fields
Authors: Coutts S. D.
Published: December 2007

Planning for the depressurization of the Brent Field required an extensive study of the aquifer to determine the withdrawals necessary to depressurize the field and to predict the effect of depressurization on surrounding fields. Static and dynamic aquifer models were constructed and several techniques were applied to evaluate the sealing capacity of the major boundary fault. Since the aquifer extends over several license blocks, integration of a wide range of data of varying quality from different sources was required to build up a complete aquifer model. The results highlighted effects of pressure communication between fields which were not apparent to teams studying individual fields in isolation.
Probabilistic Investigation of Foundation Design for Offshore Gravity Structures
Authors: Kraft L.M. , Murff J.D.
Published: December 2007

This paper lays the groundwork for establishing foundation safety criteria for offshore gravity structures. The concepts are explained in terms of first- and second-order uncertainty analyses. Various uncertainties associated with foundation analyses are identified and applications are illustrated with examples.

Introduction

Gravity structures play a prominent role today in North Sea oil development. These structures are not supported by piles, as are most ocean structures, but rather sit directly on the ocean bottom and depend on their foundation geometries and large weights m resist severe environmental loadings. A number of structural and foundation configurations have been proposed; however, attention is restricted here to a general configuration typical of the most prominent structures presently being constructed. prominent structures presently being constructed. An example of a gravity structure is illustrated in Fig. 1. The structure foundation consists of a large caisson placed directly on the unprepared sea-bed surface. The deck is supported by large columns extending from the caisson. Various combinations of steel and reinforced concrete have been proposed, but most structures are being constructed almost entirely of reinforced and prestressed concrete. prestressed concrete. One of the primary engineering concerns with these structures is foundation design. Because of the variability associated with the environmental forces, as well as the basic soil properties, this problem lends itself well to modem probabilistic problem lends itself well to modem probabilistic procedures. Such procedures provide a rational, procedures. Such procedures provide a rational, quantitative means for evaluating uncertainties affecting appropriate design, even though a degree of subjectivity will always remain in any such evaluation. The probabilistic method requires the engineer to formally and consistently recognize die variability of many of the important design parameters. The method gives management and parameters. The method gives management and others responsible for setting design criteria an opportunity to appraise cost/benefits of design levels required for given reliability levels. It also quantifies reliability to permit direct comparison with other options.

This paper presents a method for analyzing the reliability of gravity-structure foundations in terms of simple loading and resistance models. The sources of variability in estimating resistance to loads are discussed, with particular emphasis on the nature of soil-property variability and uncertainty. These concepts are illustrated through an analysis of a typical gravity-structure foundation.

SPEJ

P. 97
Generalization of the Maxwell Equation for Formation Resistivity Factors(includes associated papers 6556 and 6557 )
Authors: Perez-Rosales C.
Published: December 2007

A formula relating porosity and formation resistivity factor is presented.This equation is applicable not only to consolidated and unconsolidatedmaterials, but also to dispersive systems. A comparison of calculatedvalues with experimental data shows the equation yields satisfactory results.

Introduction

The formation resistivity factor of a porous sample hasbeen defined as the ratio of the resistivity of the samplewhen completely saturated with an electrolyte to theresistivity of the saturating electrolyte. One of thetheoretical expressions relating the formation resistivityfactor, F R, to porosity, phi, is known as the Maxwellequation. Its form is

3 −F = ---------- ...........................(1)R 2

This equation can be applied to dispersive systems ofspheres, where electrical interference among theelements is negligible.

In practice, little attention has been paid to Eq. 1, mainly because its application is limited to idealizedsystems. However, contrary to other empiricalexpressions currently used, it has the virtue of having arigorous theoretical deduction.

In view of the potential importance of Eq. 1, andbecause the idealizations made in its derivation are notwell known, a theoretical development is presented inthe Appendix, according to the ideas suggested byMaxwell.

Theory

Outstanding among the attempts to generalize theMaxwell equation is the work of Fricke, whotheoretically demonstrated that for dispersive systems of oblate and prolate spheroids

(x + 1) −F = -------------,.........................(2)R x

where x is a geometric parameter that is a function ofthe axial ratio of the spheroids, and whose value is lessthan 2. When x = 2, Eq. 2 reduces to Eq. 1.

Fricke confirmed Eq. 2 by using experimental dataon the conductivity of blood. For this purpose, hetreated the red corpuscles as oblate spheroids. Furthermore, he made use of the fact that the redcorpuscles behave as perfect insulators for director low-frequency current; this behavior results frompolarization effects.

It is interesting to note that Maxwell's formula forspheres and Fricke's equation for spheroids areequilateral hyperbolas that can be written as

P(1−) F = 1 + -----------,.......................(3)R

where P takes on the values of 1.5 and (1 + x)/x, respectively. Furthermore, P is a geometric parameterwhose value becomes larger as the sphericity becomessmaller. Similarly, it has been found that, in the caseof two-dimensional dispersive systems, a relationship ofthe form of Eq. 3 is also satisfied. However, it shouldbe noted that idealizations have been made in itsderivation that, in principle, do not allow its applicationto those cases where the elements are in contact or neareach other, or when they have irregular shapes. Therefore, Eq. 3 should be modified if it is to be applied to real cases.

For this purpose, consider a system of spheres, whether disperse or in contact. Fig. 1 shows some ofthe flowlines in the neighborhood of two spheres incontact.

JPT

P. 819^
Sand Jet Perforating Revisited
Authors: Cobbett J. S.
Published: December 2007

Though sand jet perforating is not a new technique, it is one that has been almost forgotten, the last SPE paper on the subject being published in 1972. Unlike explosive perforating, which is literally a "one shot" process, sand jet perforating uses a high velocity jet of abrasive fluid to cut through the casing, cement and deep into the formation, enabling pressure, pumping time and other parameters to be varied to maximize penetration. Sand jets can penetrate much deeper than explosives, and offer a cost-efficient, safer and better-targeted alternative to hydraulic fracturing to bypassing deep near-wellbore damage.

This paper is based mainly on experience in Lithuania, where, in 1995, joint venture oil companies first started field operations to complete development of small oil fields found in the west of the country (see Fig. 1) during the Soviet era, but which had been considered as too small to develop for the Soviet Union, with giant oil fields to the east. Wells, some of which had produced on test at over one thousand barrels per day, had been left with heavy mud across open perforations, often for more than a decade. When it proved impossible to get these wells to flow again using (western) tubing conveyed explosive perforators (TCPs), sand jetting was used, as has been the almost universal practice in Lithuania. The first well sand jet perforated by a joint venture company, which had yielded less than one barrel per day with (western) TCPs, gave over 900 barrels per day when perforated with sand jets.

Subsequently, one of the best producers in Lithuania, which had already been sand jetted once, was reperforated using more advanced techniques. Coiled tubing was run through the xmas tree and completion to enable the well to be sand jet perforated, with oil as the carrier fluid, underbalanced, with the well flowing throughout, resulting in a doubling of production to 800 BOPD.

Though sand jet perforating is, at least theoretically, available from the main pumping contractors, it is almost unknown outside North America and the former Soviet Union, the main technical references (Refs. 1–5) being over 30 yr old. Sand jet perforating does, however, provide a cost-effective means of passing deep formation damage and should form part of the armory of any practicing petroleum engineer. This paper aims to remind engineers of this, review the technology and suggest appropriate applications.
Use of Analytical Solutions To Improve Simulator Accuracy
Authors: Jasti J. K. , Penmatcha V. R. , Babu D. K.
Published: December 2007

Analytical solutions previously developed for wellbore design and scoping analysis were utilized in this study to benchmark and modify the existing wellbore models in the reservoir simulator. The analytical solutions were developed for single phase oil or gas flow problems, and they are currently being used for well performance studies covering a wide range of well configurations: vertical, horizontal, deviated, and arbitrary well geometry, and fractured completions in single or multilayered reservoirs. In this paper, some of the analytical solutions are utilized for benchmarking the existing well models in the reservoir simulator. Alternative well models are proposed for improving the accuracy of simulator predictions. Two methods of calculating gridblock-wellbore-connection factors are described. Results show that the new methods impact the simulator accuracy significantly for three-dimensional flow cases and for highly deviated wells.
Surfactant Aging: A Possible Detriment to Tertiary Oil Recovery
Authors: Cash R.L. , Cayias J.L. , Hayes M. , McAllister D.J. , Schares T. , Schechter R.S. , Wade W.H.
Published: December 2007

Introduction

New processes for achieving improved oil recovery have been under development in the petroleum industry for many years. One such process, termed surfactant flooding uses surfactants to minimize oil/water capillary forces. The petroleum sulfonates are of interest as surfactants by virtue of their low cost. However, there are problems. Foster has shown that the low interfacial tensions required for efficient displacement are sensitive functions of surfactant concentration and salinity.

Aqueous solutions of petroleum sulfonates appear to change with time. This tension aging has been found to occur in both the presence and absence of certain cosurfactants. Also visually striking are the metamorphic changes that slowly occur when the surfactant is carefully contacted with an aromatic hydrocarbon without mixing the two phases. The aging processes described here evolve through nonequilibrium states, some of which may be detrimental to oil-recovery processes. These nonequilibrium aging states develop slowly (over a period of months, perhaps even years) and would not influence model displacements lasting only a few days or weeks; but they would be significant in the time frame over which a tertiary oil-recovery program is conducted.

Experimental Procedure

All the pure hydrocarbon oils studied were spectroscopic grade. Further purification had no effect on their interfacial tensions and, therefore, they were used as received from the manufacturer, Chem Samples. The hydrocarbon mixture designated as pseudocrude is described elsewhere. Witco Chemical Co. supplied the petroleum sulfonate designated as TRS 10-80, and Shell Development Co. provided the Martinez 380 and Martinez 470.

The aqueous surfactant/salt solutions were prepared using the surfactant as received, always adding the sodium chloride last.

All the interfacial tension measurements were made without pre-equilibrating the two phases. The values of the tensions for these systems were obtained at 25 deg. C using a spinning-drop interfacial tensiometer.

Results and Discussions

Low Tensions and Surfactant Aging

A substantial difference in some interfacial tensions was discovered when two surfactant solutions of differing ages were used to measure the interfacial tensions of three homologous hydrocarbon series. These three hydrocarbon series were (1) n-alkanes from pentane to heptadecane, (2) n-alkylbenzenes or 1-phenylalkanes from benzene to heptadecylbenzene, and (3) n-alkylcyclohexanes or 1-cyclohexylalkanes from cyclohexane to n-tridecylcyclohexane. Both aqueous phases conMined 0.2-percent surfactant/1.0-percent salt and were prepared using the same technique. prepared using the same technique. JPT

P. 985
Effect of Coiled-Tubing Initial Configuration on Buckling Behavior in a Constant-Curvature Hole
Authors: Qiu Weiyong , Miska S. Z. , Volk L. J.
Published: December 2007

In practical coiled tubing drilling and completion operations, minor curvature always exists in coiled tubing (CT). The authors ("Effect of Coiled Tubing Initial Configuration on Buckling/ Bending Behavior in Straight Deviated Wells," paper SPE 39003 Presented at the 1997 Fifth Latin American and Caribbean Petroleum Engineering Conference and Exhibition held in Rio de Janeiro, Brazil, 30 August-3 September) previously published that the initial CT configuration results in the reduction of the axial compression force required to produce helical configuration in a deviated well. In this paper, the authors emphasize the effect of initial CT configuration, or residual bending, on buckling behavior in a hole of constant curvature. By utilizing the conservation of energy and the principle of virtual work, new equations are derived to predict the axial compression force for a stable sinusoidal configuration and the axial compression force required to produce a helical configuration. These new equations reduce to those previously published when CT has not been initially bent. Practical examples are presented to demonstrate the effect of the initial amplitude on both sinusoidal and helical buckling behavior of CT in curved wells. The results indicate that the radius of curvature of a borehole is a governing parameter that influences CT buckling behavior. The effect of the initial CT configuration on sinusoidal configuration can be neglected, whereas the effect of the initial CT configuration on helical configuration is substantial. The results will help field engineer to understand CT buckling behavior, and consequently, to select the proper CT to avoid lockup and to improve the prediction of the axial force transmission in horizontal and extended reach drilling.
The Material Balance as an Equation of a Straight Line
Authors: Havlena D. , Odeh A.S.
Published: December 2007

The material balance equation used by reservoir engineers is arranged algebraically, resulting in an equation of a straight line. The straight line method of analysis imposes an additional necessary condition that a successful solution of the material balance equation should meet. In addition, this algebraic arrangement attaches a dynamic meaning to the otherwise static material balance equation.

The straight line method requires the plotting of one variable group vs another variable group. The sequence of the plotted points as well as the general shape of the resulting plot is of utmost importance. Therefore, one cannot program the method entirely on a digital computer as is usually done in the routine solution of the material balance equation. If this method is applied, then plotting and analysis are essential.

Only the appropriate equations and the method of analysis and interpretation with comments and discussion are presented in this paper. Illustrative field examples for the various cases treated are deferred to a subsequent writing.

Introduction

One of the fundamental principles utilized in engineering work is the law of conservation of matter. The application of this principle to hydrocarbon reservoirs for the purpose of quantitative deductions and prediction is termed "the material balance method of reservoir analysis". While the construction of the material balance equation (MBE) and the computations that go with its application are not difficult tasks, the criteria that a successful solution of the MBE should fulfill have always been a problem facing the reservoir engineer.

True and complete criteria should embody necessary and sufficient conditions. The criteria which the reservoir engineer uses possess a few necessary but no sufficient conditions. Because of this, the answers obtained from the MBE are always open to question. However, the degree of their acceptability should increase with the increase in the number of the necessary conditions that they should satisfy.