bluuebunny/crossref_metadata_2025 huggingface dataset:
A New Technique for Examination of Oilfield Brines
Authors: Aycock W.P. , Hough E.W. , Crawford George W.
Published: December 2007

Forty oilfield brines have been examined so far by a polarographic technique new in petroleum engineering called the "tensammetric method" by the team of biochemists who perfected its use in their field. Samples of brine were obtained from various oil fields in which the wells were known to be producing fluid from oil productive zones in well-known geologic formations. Most of the reservoirs from which the samples were obtained are believed to have an active water drive under the prevailing conditions of operation. The 40 samples represent brines produced from 16 different formations of various geologic ages.

Graphs have been prepared of the data obtained in the testing of each sample, and the distinctive wave-like curves so obtained are characterized by reproducible profiles, called "response curves." Careful comparison of the response curves of salt water coming from different fields producing from the same geologic formation reveals that the curves are similar. The response curves of salt water coming from productive zones of different geologic formations are characteristically different.

Preliminary work offers the further hope that response curves of an oilfield brine indigenous to a particular oil-bearing formation and hence representative of a particular geologic environment, such as depositional and all subsequent morphological conditions, may be of value in reservoir engineering in the interpretation of surface and interfacial phenomena. For example, the wettability of the rock matrix and more specifically, the classification of productive oil-bearing strata as hydrophyllic or hydrophobic may be determinable. However, many more brines must be examined and the resulting response curves analyzed in comparison to known causal phenomena before this objective is achieved.

Introduction

One of the perennial moot questions in the literature of petroleum engineering is whether the reservoir rock is oil- or water-wet. Possibly an answer to this question could come from a careful examination of oilfield brines. None of the conventional methods of examining brines (chemical analysis, pH and electrical conductivity measurements, and the like) answer the question. Careful analysis of reservoir behavior observed in the exploitation of oil fields, particularly in the application of fluid injection, has been fruitful to the extent that a few reservoirs are believed to be properly classified.
Precise Well Placement With Rotary Steerable Systems and Logging-While-Drilling Measurements
Authors: Tribe I. R. , Burns L. , Howell P. D. , Dickson R.
Published: December 2007

This paper demonstrates profitable geosteering of a central North Sea, U.K., horizontal well with a rotary steerable system (RSS) together with new-generation azimuthal logging-while-drilling (LWD) tools. The nature of the tertiary turbidite reservoir, with only 3 million STB, meant that to be commercial, only one horizontal well should be drilled and that the following criteria had to be met.

Maximize standoff from an oil/water contact (OWC) within a sand unit with an approximately 50-ft oil column. Achieve 1,500 to 2,000 ft of good-quality reservoir. While maintaining standoff from the OWC, make a corresponding azimuth turn to follow the crestal dome structures of the reservoir trap. Avoid the risk of stuck pipe by carefully monitoring real-time drilling and well data and by using RSS technology.

During well drilling, correlation software enabled comparison of offset-well and real-time LWD data and visualization of the well's position in the reservoir sequence. This modeling complemented wellsite biostratigraphic and geological correlation work and enabled changes to the trajectory to be planned, which were then achieved while constantly rotating with the RSS. Azimuthal-density measurements were used in real time and as post-well image logs for structural dip and fault interpretation.

The well was geosteered into a sweet spot within 5 ft of the reservoir roof and as much as 56 ft from the OWC. The RSS completed the well in a single 3,844-ft run, with an average rate of penetration (ROP) of 68 ft/hr and no stuck-pipe problems. The target of 1,500 to 2,000 ft of pay was met with 1,980 ft of >20% porosity sand and 88% net to gross. The preplanned geometric wellpath would have missed the first 1,000 ft of the reservoir section, justifying the geosteering approach. A water saturation of 10% was much lower than prognosed, and the well has produced more oil than expected without early water breakthrough.

This well demonstrates the combinability of the latest RSS and LWD technology to meet ever-demanding drilling and geological objectives successfully under circumstances of high economic risk and to ultimately maximize potential well production.
Determination of Fractal Parameters of Fracture Networks Using Pressure-Transient Data
Authors: Flamenco-López F. , Camacho-Velázquez R.
Published: December 2007

The objective of this paper is to investigate the transient pressure behavior of naturally fractured reservoirs with fractal characteristics. This work is based on the findings of previous studies, which have shown that the networks of fractures in some reservoirs are fractals. Thus, using this assumption, an approximate analytical solution for dual-porosity systems is derived in the Laplace space.

The approximate solution presented in this work uses a pseudosteady-state matrix-to-fractal fracture transfer function. This solution is compared with a finite-element solution, and good agreement is found. Short- and long-time approximations are used to obtain procedures in time to determine some fractal parameters. These approximations are compared to the appropriate expressions when an unsteady-state matrix-to-fractal fracture transfer function is used.

Synthetic and field examples are presented to illustrate the methodology proposed in this work.

This paper also presents an analytical solution for the pseudosteady-state flow period and demonstrates the importance of analyzing both transient and pseudosteady-state flow-pressure data for a single-well situation to fully characterize a naturally fractured reservoir with a fractal geometry.
The Role of Surfactant Precipitation and Redissolution in the Adsorption of Sulfonate on Minerals
Authors: Somasundaran P. , Celik M. , Goyal A. , Manev E.
Published: December 2007

The presence of maxima and sometimes minima in the adsorption isotherms of surfactant on minerals has been attributed to various mechanisms involving micelle exclusion, impurities, surfactant composition, mineral morphology, etc. This study on the precipitation of sulfonates with various inorganic ions (Na, K, NH4, Ca, Mg, and Al) and the subsequent redissolution when the surfactant concentration is increased shows a precipitation maximum to occur in the same surfactant concentration range where an adsorption maximum is obtained. Simultaneous abstraction, precipitation, and adsorption experiments have been conducted using chromatographically purified dodecylbenzenesulfonate and Na-kaolinite, and the results show the "abstraction vs. surfactant concentration" curves to exhibit a much more pronounced maximum than the real adsorption (abstraction minus precipitation) maximum. We suggest that the total abstraction of surfactant from the solution on contact with mineral phase, usually called "adsorption," is a summation of both the "real" adsorption and precipitation and that the precipitation/redissolution phenomenon is one of the major reasons for the adsorption maxima. Introduction of oil into the system reduces the precipitation because of partitioning of the sulfonate between the oil and aqueous phases. Precipitation and adsorption data are used to derive possible mechanisms for the precipitation/redissolution phenomena.
Model Studies of the Depletion of Two-Phase Geothermal Reservoirs
Authors: Pruess K. , Bodvarsson G. S. , Schroeder R. C. , Witherspoon P. A.
Published: December 2007

The simulator SHAFT79 of Lawrence Berkeley Laboratory has been used to study the depletion of different types of geothermal reservoirs. Investigations of idealized systems include effects of gravity and fluid injection. Pressure decline is analyzed as a function of cumulative production. The main conclusions are as follows.

The well-known p/Z method for estimating fluid reserves is not applicable to two-phase geothermal reservoirs. There is a strong tendency toward spatially uniform boiling. This causes a pressure decline, which allows in many cases estimates of the total reservoir volume and of the total heat content of the reservoir rock. Propagation of a boiling front through a deep water table, as a consequence of fluid production, gives rise to a peculiar pattern of pressure decline. This may allow prediction of the distance of the water table from the producing wells and of the vertical thickness of the water zone, thereby giving important clues to estimating fluid reserves. The pressure effects of injection of colder fluid depend strongly on (one- or two-) phase conditions in the reservoir, injection rate, and absolute permeability. Average pressure actually may decline in two-phase reservoirs rather than increase as a result of injection.
Interwell Tracer Analyses of a Hydraulically Fractured Granitic Geothermal Reservoir
Authors: Tester Jefferson W. , Bivins Robert L. , Potter Robert M.
Published: December 2007

Field experiments with fluorescent dye and radioactive tracers (Br82 and I131) have been employed to characterize a hot, low-matrix-permeability, hydraulically fractured granitic reservoir at depths of 2440 to 2960 m (8,000 to 9,700 ft). Tracer profiles and residence time distributions (RTD's) have been used to estimate sweep efficiencies and fracture volumes and to diagnose normal and pathological flow behavior both in injection and in production wells. The effectiveness of one- and two-dimensional (1- and 2D) theoretical dispersion models using single and multiple porous, fractured zones with velocity- and formation-dependent effects is discussed with respect to actual field data.
Equilibrium Calculations on the Kelly-Snyder Reservoir
Authors: Kennedy Harvey T. , Dardaganian Stephen G. , Clanton John L.
Published: December 2007

This paper presents equilibrium ratios measured on oil and gas samples taken from the Kelly-Snyder field at the reservoir temperature of 128°F. From these data smoothed curves were constructed for the reservoir fluid up to the bubble-point, 1,874 psia. A material balance calculation, based on the use of equilibrium ratios instead of the usual solubility and shrinkage measurements is made on the field and compared to the conventional method.

Determination of Equilibrium Ratios

The equilibrium ratios, or K values were obtained by recombining separator samples of oil and gas taken when the reservoir was above its bubble point, and thus represented the reservoir fluid before any change had occurred due to the evolution of gas. The well sampled had a gas-oil ratio of 617 cu ft of high pressure separator gas per barrel of separator oil, and a bottom-hole temperature of 128°F.

Samples were brought to equilibrium by agitating for 24 hours in a thermostat, maintained at the proper temperature within 0.2 °F, mercury being added when necessary to maintain the pressure constant. Samples of oil and gas were then taken by constant pressure displacement, and analyzed by low temperature fractionation.

Equilibrium ratios were determined at 128°F and 500, 800, 1,000 and 1,400 psig. At the latter pressure, there were indications that the gas samples were contaminated with small quantities of oil, and only data taken at the first three pressures were included in Fig. 1. This figure has been extended to higher and lower pressures by the use of the Fluor charts for 3,000 psi convergence pressure, on which the experimental points fit well.

Material Balance Equations

The possible errors involved in conventional material balance equations have been analyzed by Muskat. Where the errors occur in field measurements, or in obtaining effective averages from variables such as gas-oil ratio and pressure, they will evidently be involved in any attempt to estimate the content of the reservoir.
Effects of Friction on Hydraulic Fracture Growth Near Unbonded Interfaces in Rocks
Authors: Anderson Gordon D.
Published: December 2007

Small-scale laboratory experiments were performed to study the growth of hydraulically driven fractures in the vicinity of an unbonded interface in rocks. The purpose was to evaluate under which conditions the hydraulic fractures would cross the interface. The materials used in these studies were Nugget sandstone from Utah (3 to 6% porosity) and Indiana limestone (12 to 15% porosity). The fracturing fluid was oil (viscosity ~ 300 cp) injected into the rock through high-pressure steel tubing. Prismatic blocks of the rock materials to be studied were held adjacent to one another in a hydraulic press so that a normal stress was set up across their mutual interface. Lubricants and surface roughening were used to vary the frictional properties of the interfaces. It was found that as the interface surface friction coefficient was decreased, the normal stress had to be increased for a hydraulic fracture to cross the interface. The frictional shear stress that the interface can support without slippage appears to be critical in determining fracture growth across the interface. Additional experiments were performed to evaluate the coefficient of friction for the different interface surface preparations used. These experiments demonstrated that a variation in the frictional properties along an interfacial surface in the vicinity of hydraulic fracture growth can alter the path of the fracture. The experiments also demonstrated that cracks, which intersect the interface from the side opposite the approaching hydraulic fracture, can impede fracture growth across the interface.
Evaluation of Wireline Down-Log Information and Effects of Increased Log Speeds on Data Quality
Authors: Hartley Kevin B.
Published: December 2007

Wireline logs run in deviated Gulf of Mexico wells using new logging techniques are studied. Formation density and other logs can be recorded logging in or out of a hole at very high speeds and often provide excellent evaluation information. Down logs can be very useful in the event the usual up log becomes impossible. Increased log speeds may be justified in some cases involving hole problems or high rig costs.

Introduction

A study has been made of openhole wireline logs run in deviated wells in the Gulf of Mexico. Some new logging techniques of interest have been made possible by the introduction of computerized digital possible by the introduction of computerized digital surface logging units. Many of these techniques could not have been used previously due to limitations of the conventional analog surface logging units.Logs run going in the hole (down logs) often can provide valuable formation evaluation information, provide valuable formation evaluation information, particularly porosity data. Sometimes hole conditions particularly porosity data. Sometimes hole conditions are severe enough that the logs run coming up from total depth are not obtainable. Down-log porosity data often can distinguish hydrocarbon-bearing from tight zones and even oil from gas.Of particular interest is the observation that the formation density tool often can provide very good average porosity values when logged going in a deviated hole at a speed of 10,000 ft/hr with the caliper arm closed (Figs. 1 and 2). Down logs using other types of logging tools also have provided critical evaluation information.The accuracy of depth information is a problem, but zone thicknesses often are correct and depth errors can be estimated.The repeatability of various log types when run at speeds higher than normal also has been studied. Formation density logs run in high-porosity formations at 3,000 and 5,000 ft/hr show only minor variations from logs run at the conventional speed of 1,800 - ft/hr (Figs. 3 and 4). This excellent repeatability is due to the high gamma-ray count rates of the density tool in the offshore low-density formations of Pleistocene age. In fact, the variations observable between density logs run over a common interval in these low-density formations may be primarily a function of wall contact effects, not the primarily a function of wall contact effects, not the random statistical count rate variations. Statistics for the compensated neutron and gamma-ray devices relative to logging speed also are studied.Induction-type devices have been run at speeds up to 15,000 ft/hr with excellent repeatability using the computerized surface units.This paper is not intended to be a recommendation for increases in log speeds, particularly for the porosity devices. Increased formation density log porosity devices. Increased formation density log speeds in complex lithologies, for example, could reduce the value of the data greatly.

JPT

P. 1151
Numerical Simulation of Water Injection in Fractured Media Using the Discrete-Fracture Model and the Galerkin Method
Authors: Karimi-Fard Mohammad , Firoozabadi Abbas
Published: December 2007

Numerical simulation of water injection in discrete fractured media with capillary pressure is a challenge. Dual-porosity models, in view of their strength and simplicity, can be used mainly for sugar-cube representation of fractured media. In such a representation, the transfer function between the fracture and the matrix block can be calculated readily for water-wet media. For a mixed-wet system, the evaluation of the transfer function becomes complicated because of the effect of gravity.

In this work, we use a discrete-fracture model in which the fractures are discretized as ID entities to account for fracture thickness by an integral form of the flow equations. This simple step greatly improves the numerical solution. Then, the discrete-fracture model is implemented using a Galerkin finite-element method. The robustness and the accuracy of the approach are shown through several examples. First, we consider a single fracture in a rock matrix and compare the results of the discrete-fracture model with a single-porosity model. Then, we use the discrete-fracture model in more complex configurations. Numerical simulations are carried out in water-wet media as well as in mixed-wet media to study the effect of matrix and fracture capillary pressures.
Northstar Drilling—Delivering the First Arctic Offshore Development
Authors: Krieger Andrew G. , Kidd Gavin N. , Cocking David A.
Published: December 2007

Northstar is the first arctic offshore development that is not accessible by road for most of the year and does not have fixed-wing air support. The implications of limited access to a 400×400-ft island are enormous. Successful completion of the first drilling season at Northstar is a significant milestone marked by detailed design and execution as well as pure determination. Many of the challenges were anticipated and accounted for, while many others were not. These challenges included environmental hurdles, logistical constraints, and commissioning the rig and the grind and inject (G&I) facility on an accelerated schedule. The first arctic offshore development delivered its first barrels of oil as per schedule on 2 November 2001. Now comes the next challenge—drilling to improve the profitability of this unique Alaskan project.
A Well-Test Analysis Method Accounting for Pre-Test Operations
Authors: Silin D. B. , Tsang C. -F.
Published: December 2007

In recent work, we have extended the classical radial flow model used in a standard pressure drawdown or buildup well-test analysis by incorporating an additional parameter characterizing the pumping rate prior to the test. By this means, we develop an approach for estimating the formation hydraulic properties in the vicinity of the wellbore from regular pumping rate-pumping pressure data. In this paper, the approach is established as a well-test analysis method by accomplishing two steps. First, five parameters, including the reservoir transmissivity, storativity, skin factor, and pre-test pumping rate, are determined from analysis of measured data. Second, the average reservoir pressure and drainage radius are determined from a calculation using parameters obtained in the first part.
Application of Wavelet Transform to the Analysis of Pressure-Transient Data
Authors: Soliman M. Y. , Ansah J. , Stephenson S. , Mandal B.
Published: December 2007

Although the mathematical concept of "wavelet transform" was developed in the early part of the 20th century, it did not receive practical application until the 1980s. Wavelet transform is now used in a wide variety of applications in the areas of medicine, biology, and data compression, among others. A significant benefit provided by wavelet transform is its capability to provide two functions:

Smoothing of the basic signal. Retention or even enhancement of the details.

In data analysis, these characteristics allow the user to recognize hidden signals quickly. In well testing, these capabilities can enhance signals that can be masked by other events or by the data frequency itself. Because the derivative techniques currently used in well testing tend to smooth data and conceal certain events, the use of the wavelet transform to analyze the raw data could prove to be very valuable as a major step in enhancing the techniques of modern data analysis.

This paper briefly reviews the application of the wavelet transform methodology to data analysis in general and shows why its application to well-testing data in particular is important. It also provides guidelines for the application of this technology to well testing.

Several field examples are provided to demonstrate the application of the wavelet transform to well testing and to show how the qualitative and quantitative uses of the method determine wellbore anomalies, boundary effects, and other well-testing phenomena.
Plunger-Lift Monitoring by Analyzing Wellbore High-Frequency Acoustic Signals and Tubing and Casing Pressures
Authors: McCoy Jim , Rowlan Lynn , Podio A. L.
Published: December 2007

Plunger-lift operations are difficult to optimize owing to a lack of knowledge concerning tubing, casing, and bottomhole pressures; liquid accumulation in the tubing; and the location of the plunger. Monitoring plunger position in the tubing helps the operator understand the operation of the plunger system to optimize the removal of liquids and gas from the well. Plunger position can be tracked from the surface by monitoring the acoustic signals generated as it falls down the tubing. When the plunger passes a tubing collar recess, an acoustic pulse is generated that travels up the gas within the tubing and can be monitored at the surface by a microphone and/or a sensitive pressure transducer. The digitized signal is processed to display plunger depth and velocity and well pressures vs. time. Plunger arrival at the liquid level in and at the bottom of the tubing are identified on the time plots. A field case is presented to show how this information can be applied to optimize plunger-lift operations.
Damage Characterization of Deep Bed Filtration From Pressure Measurements
Authors: Bedrikovetsky P. , Tran T. K. , Van den Broek W. M. G. T. , Marchesin D. , Rezende E. , Siqueira A. , Souza A. L. , Shecaira F.
Published: December 2007

Permeability decline occurs during injection of sea or produced water, resulting in well impairment. Solid and liquid particles dispersed in the injected water are trapped by the porous medium and may significantly increase hydraulic resistance to the flow.

We discuss a mathematical model for deep bed filtration containing two empirical parameters - the filtration and the formation damage coefficients. These parameters should be determined from laboratory coreflood tests by forcing water with particles to flow through core samples. A routine laboratory method determines the filtration coefficient with expensive and difficult particle-concentration measurements of the core effluent, and then the formation damage coefficient is determined from inexpensive and simple pressure-drop measurements.

An alternative method would be to use solely pressure difference between the core ends. However, we proved in an earlier work that given pressure-drop data in seawater coreflood laboratory experiments, solving for the filtration and formation damage coefficients is an inverse problem that determines only a combination of these two parameters rather than each of them.

A new method for the simultaneous determination of both coefficients is developed here. The method's new feature is using pressure data at an intermediate core point, supplementing pressure measurements at the core inlet and outlet. The proposed method furnishes unique values for the two coefficients, and the solution is stable with respect to small perturbations of the pressure data.

In this work, the proposed method is used for analysis of laboratory test data on deep bed filtration. The values of filtration and formation damage coefficients are obtained for flow of solid and liquid particle dispersions in a number of different cores. Effects of particle type and porous media wettability on permeability decline are analyzed.
Compositional Model Studies – CO2 Oil-Displacement Mechanisms
Authors: Leach M. P. , Yellig W. F.
Published: December 2007

This paper presents matches, using a fully compositional model, of the performances of seven laboratory CO2 displacements of a 10-component synthetic oil. The criteria for achieving a match of laboratory performance include (1) comparisons of predicted and experimentally determined oil recovery and (2) effluent compositional profiles for each component as functions of hydrocarbon pore volumes (HCPV) of CO2 injected.

An equation of state was tuned to predict single-contact (PVT) phase equilibria for CO2/synthetic-oil mixtures. The model incorporates this equation of state to predict the multiple-contact phase equilibria during a CO2 displacement test. Input to the model were independently determined gas/oil relative permeability characteristics and – for each laboratory displacement – injection rate, effluent pressure, pore volume, and temperature.

The experimental displacements were conducted in linear Berea core systems using a synthetic (C1-C14) oil at 120 and 150°F. Three displacements at 120°F have been published by Metcalfe and Yarborough.1 Previously, it was thought that these displacements were conducted at selected pressures so that oil displacements encompassed immiscible, multiple-contact miscible (MCM), and contact miscible mechanisms. However, the model results show that only contact miscible and MCM displacement mechanisms were involved. To confirm the mechanistic understanding at 120°F, three additional laboratory displacements were conducted at 150°F. These encompassed pressures such that the displacement was controlled by an immiscible, an MCM, and a contact miscible mechanism, respectively. The model results at 150°F match the ex-perimental data and confirm the mechanistic understanding. The experimental and numerical results are in agreement with the minimum miscibility pressure theory of Yellig and Metcalfe.2

The results of this study confirm the importance of experimentally determined effluent compositional profiles and fully compositional models for CO2 mechanism studies.
Use of Surfactant to Reduce CO2 Mobility in Oil Displacement
Authors: Bernard George G. , Holm L. W. , Harvey Craig P.
Published: December 2007

This paper presents results from a study designed to improve effectiveness of CO2 flooding by reducing CO2 mobility. In the course of reaching this objective we (1) screened surfactants for their ability to generate an effective and stable emulsion with CO2 under reservoir conditions, (2) determined the concentration range over which surfactants were effective, (3) examined chemical stability of the surfactants at reservoir conditions, (4) determined the extent to which emulsifying action alters gas and liquid mobilities in carbonate and sandstone cores, (5) determined that surfactant can enhance the production of residual oil from watered-out carbonate cores by CO2, and (6) showed that the permeability reduction caused by surfactant can be dissipated.

At reservoir conditions required for miscible displacement, carbon dioxide exists in its critical state as a very dense fluid whose viscosity is about one-eighth that of crude oil. Generally, this unfavorable viscosity and mobility ratio produces inefficient oil displacement. This study shows that surfactant reduces CO2 mobility and should improve oil displacement by CO2, presumably by reducing flow through the most permeable zones, thus increasing areal and vertical sweep efficiencies.

All three classes of surfactants (anionic, cationic, and nonionic) were found to be stable under conditions encountered during a CO2 flood in limestone formation; however, only a few surfactants had proper adsorption and emulsifying properties. Surfactant generated foams or emulsions with CO2 at reservoir conditions (1,000 to 3,000 psi and 135°F) dramatically reduced CO2 flow through sandstone and carbonate cores. Surfactant reduced the amount of CO2 used to recover a given volume of oil, especially from watered-out cores. The mechanism of tertiary oil production from linear cores appears to be limited to CO2 extraction. Approximately the same oil recovery was obtained either by continuous CO2 injection after a surfactant slug or by alternate slugs of CO2 and surfactant solution. It was found that oil recovery efficiency increased when surfactant was used with CO2 and that efficiency increased with flooding pressure.

One anionic surfactant was found to be superior for this purpose. This surfactant emulsified CO2 well, was least adsorbed on carbonate rocks, and greatly reduced CO2 mobility in linear cores at concentrations of 0.1 to 1%.

The study indicates that effectiveness of CO2 miscible flooding can be increased by alternate injection of CO2 and aqueous surfactant slugs into the reservoir.
Performance Improvement Techniques Used on Goodwyn A Platform, Northwest Shelf, Australia
Authors: Dolan S. P. , Williams G. J. , Barrows W. J. , Dickson J. W. , Torry D. , Drury R. F.
Published: December 2007

This paper reviews the techniques that have generated a large improvement in drilling and completion performance on the Goodwyn A Platform, Northwest Shelf, Australia. The collective effort of well-construction professionals using these techniques has resulted in the drilling of a 6263-m (20,550-ft) total depth (TD) well with a horizontal stepout of 5200 m (17,060 ft) at a tangent angle of 67° in 39 days from spud to well handover. This was 31% under the P50 authorization-for-expenditure (AFE) time estimate.

This paper describes a method to produce systematic, steady, and sustainable improvements to well-construction operations. The methods described are a way of harnessing the collective brainpower of well-construction professionals and focusing that energy toward rigorous problem analysis or potential improvement areas, then systematically working through and implementing solutions.

The technical limit methodology and performance improvement groups (PIGs) are best suited for complex, high-cost drilling projects, typically extended reach drilling (ERD) developments, high-cost mobile offshore drilling units (MODU) exploration or subsea operations.

In addition, other tools, such as hazard management, learning system, and planning processes that contributed to success, are explained.
Application of the Theory of Multicomponent, Multiphase Displacement to Three-Component, Two-Phase Surfactant Flooding
Authors: Hirasaki George J.
Published: December 2007

The theory presented in a companion paper1 is illustrated for the case of three-component, two-phase (i.e., constant-salinity) surfactant flooding. The utility of this method is that, in addition to computation of specific cases, it provides a general qualitative understanding of the displacement behavior for different phase diagrams and different injection compositions. The phase behavior can be classified as to whether the partition coefficient is less than or greater than unity. The injection composition of the slug can be classified as to whether it is aqueous or oleic and whether it is inside or outside the region of tieline extensions.

The theory provides an understanding of the displacement mechanisms for the three-component, two-phase system as a function of phase behavior and injection composition. This understanding aids the interpretation of phenomena such as the effects of dispersion, salinity gradient, chromatographic separation, and polymer/surfactant interaction.
An Experimental Investigation of the Effect of Temperature on Recovery of Heavy Oil From Diatomite
Authors: Tang G.-Q. , Kovscek A. R.
Published: December 2007

An X-ray computed-tomography (CT) scanner, in combination with a novel high-temperature and high-pressure core holder, was used to investigate systematically heavy oil recovery from outcrop diatomite and field core. Temperatures ranged from 20 to 180°C, and all experiments are isothermal. Decane, two viscous white mineral oils, and heavy crude oil from the field were used as oil phases. In reservoir core filled with crude oil, oil recovery by spontaneous imbibition of water increased from 3% at 40°C (reservoir temperature) to 40% of oil in place at 180°C. Forced displacement brought total recovery to more than 50%. Thermal methods are effective at improving oil recovery from low-permeability, fractured oil-rock systems filled with moderate to viscous oil, whereas waterflood is not.

Recovery increases with temperature because oil viscosity decreases and wettability is altered toward water wetness. Increased imbibition rate and oil recovery corresponded with production of oil-wet fines at elevated temperature. A mechanism for increase in water wettability is proposed whereby fines detachment from pore surfaces increases the water-wet surface area.
Experimental and Theoretical Studies on the Fluid Properties Required for Simulation of Thermal Processes
Authors: Lee S. T. , Jacoby R. H. , Chen W. H. , Culham W. E.
Published: December 2007

Experimental phase equilibrium data are presented for three reservoir oils at conditions approximating those encountered in in-situ thermal recovery processes. The fluid systems involved consist of three major groups of components: flue gas, water, and crude oil. Data were measured at temperatures from 204.4 to 371.1°C (400 to 700°F) and pressures from 6996.0 to 20 785.6 kPa (1,000 to 3,000 psia). Experimental phase equilibrium data were used to develop a correlation of binary interaction coefficients of crude-oil fractions required for the Peng-Robinson equation of state. Phase equilibrium data predicted using the Peng-Robinson equation of state, using our interaction coefficients, are compared with experimental data. Generally, the Peng-Robinson equation of state predictions were in close agreement with the experimental data. Effect of feed gas/oil ratio and water/oil ratio on the equilibrium coefficients was examined through the Peng-Robinson equation of state. A study on the feasibility of representing the crude oil by only two fractions was made also. This study includes a procedure for lumping the crude-oil fractions and examples showing the importance of mixing rules in determining the pseudocritical properties of lumped fractions.
Xanthan Biopolymer Semipilot Fermentation
Authors: Norton Charles J. , Falk David O. , Luetzelschwab Wayne E.
Published: December 2007

Using standard microbiological techniques in a semipilot plant-scalable fermenter, xanthan-specific culture techniques developed by the U.S. Dept of Agriculture's Northern Regional Research Laboratory (NRRL) were used at Marathon Oil Co.'s Denver Research Center (DRC) to obtain improved and reproducible high conversions and yields of xanthan biopolymer broth. Practical nutrients and fermenter parameters were studied to define and improve the viscosity performance and economics of xanthan broth production for thickening water in the Maraflood™ enhanced oil recovery process.
Gravel Pack and Formation Sandstone Dissolution During Steam Injection
Authors: Reed M.G.
Published: December 2007

Laboratory and field flow studies show gravel-pack sands and formation sandstones may be dissolved rapidly in steam generator effluents. Dissolution rates are affected markedly by changes in solution pH and temperature. Photographs and scanning electron micrographs show changes in rock morphology caused by silica dissolution.

Introduction

Steam stimulation and steamflooding of oil reservoirs have been used for many years to help produce viscous oil more effectively. Recently it was shown that steam drive also was applied successfully in a relatively low-viscosity oil reservoir. This success combined with the need to increase domestic oil production may lead to expanded use of steam injection in the oil field.In cyclic steam stimulation it is common to inject perhaps 3000 m3 (18,870 bbl) of 80% quality steam at about 260 degrees C (500 degrees F) on each of several stimulation cycles. Thus, a few thousand cubic meters of liquid-phase water (20% of total) may be injected into a well during several steam stimulation cycles. In the case of a steam-drive injection well, tens of thousands of cubic meters of liquid are injected into the formation over the life of a project. If the formation rock and any gravel pack that may be in the well have any significant solubility in the flowing fluid, a rather large amount of rock could be dissolved. For example, if rock solubility is only 100 ppm (100 mg/L), 10 000 m3 of injected fluid will dissolve 1000 kg (2,200 lbm) of rock. If this dissolution occurs rapidly, a gravel pack would be short-lived. In the case of a large loss of formation rock from the immediate well area, formation caving and perhaps even casing or liner collapse could result.Quartz and other siliceous minerals have very low solubilities at room temperature, but at elevated temperatures solubilities increase rather sharply (Fig. 1) as reported by Krauskopf. Thus, there is ample Si solubility at normal steam injection temperatures to cause concern, although the actual rate of dissolution is not known. However, the rate is as important as solubility because it determines if severe dissolution occurs in or immediately adjacent to the injection wellbore or if it occurs less intensively over a larger radius.Solution pH also is an important factor influencing the extent and rate of Si dissolution. When HCO3 ions in steam generator feedwater decompose to CO2 and OH ions, the CO2 partitions to the vapor phase and the OH ions partition to the liquid phase. This causes the pH of the generator liquid effluent to increase sharply, the extent of which is dependent on the HCO3 content of the feedwater. Some of the OH ions react with remaining HCO3 ions to form CO3 ions, which also are quite alkaline. Measurements on samples of liquid effluent collected from field generators show that about one-third to one-half of the alkalinity is from CO3 ions and the rest is from OH ions.

JPT

P. 941＾
Application of Large Computers to Reservoir Engineering Problems
Authors: McCarty D.G. , Peaceman D.W.
Published: December 2007

The primary applications of automatic computing equipment to the field of engineering are (1)the development of engineering information more economically and (2) the production of improved engineering analyses. While experience has demonstrated that both large and small computers are useful in the first application, it presently appears that the large computer will be required to investigate multiphase flow and to predict the flow behavior of oil and gas reservoirs considering two- and three-space dimensions.

Some of the mathematical difficulties which arise in connection with the equations describing flow of fluids in oil and gas reservoirs are briefly reviewed, and some of the recent developments in the application of numerical techniques to reservoir engineering problems are discussed. The general computational requirements for typical problems of this type are included, and the specific time requirements for effective application of a few of the newer analyses to actual reservoir cases using both large and small computers are compared.

Introduction

The advantages of using high-speed computing equipment in engineering work fall generally into two categories. First, it is possible to conserve engineering manpower in that the inherent high computing rate of these devices can be directed so as to perform the engineering calculation work of many men. The second and potentially more significant advantage afforded by effective application of the high-speed computer is the ability to produce information which otherwise would not be available to the engineer. This is usually made possible by employing new or improved methods of analysis.

New and improved methods of engineering analysis are beginning to evolve from the aggressive research programs on the application of numerical methods which various industrial research groups initiated five to 10 years ago. Techniques have been developed for studying problems in reservoir mechanics, such as unsteady gas flow and flow of single-phase fluids in two- and three-space dimensions, and improvements have been made in techniques for studying multiphase flow.
Maximizing Yibal's Remaining Value
Authors: Mijnssen F. C. J. , Rayes D. G. , Ferguson I. , Al Abri S. M. , Mueller G. F. , Razali P. H. M. A. , Nieuwenhuijs R. , Henderson G. H.
Published: December 2007

Reserves in Yibal traditionally have been targeted by infill drilling, initially with vertical wells and, since 1994, with horizontal wells. Since 1999, new well results have been disappointing, and drilling was suspended in early 2001. An integrated field review was kicked off to design the next era of Yibal development to maximize the remaining value.

The review began with an integrated well and production review. This review concluded that horizontal wells drilled in 1994 and 1995 produced significantly more oil than the original vertical wells. However, later horizontal wells produced similar amounts of oil as the vertical wells, but at much higher water cut.

Based on the well and production review, 13 development opportunities have been identified. A focus area was identified within the field to test these development opportunities. A comprehensive data-gathering campaign of production and saturation logging has been completed in addition to detailed integrated modeling. Subsequently, two infill wells were drilled targeting bypassed oil pockets. These wells confirmed the data-gathering and modeling results and highlighted the further development potential in the Yibal field.
Interfacial Effects in Gas-Condensate Recovery and Gas-Injection Processes
Authors: Meleán Y. , Bureau N. , Broseta D.
Published: December 2007

This paper evaluates the behavior of the dimensionless numbers that gauge the gas/oil interfacial tension (IFT) with respect to the other forces (viscous and buoyancy forces) involved in two-phase flow through porous media. These numbers, referred to respectively as the capillary and Bond numbers, diverge on approach to gas/oil complete miscibility, meaning that viscous and buoyancy forces become dominant over capillary forces. The divergence behaves as a power of the distance to complete miscibility as quantified, for instance, by the difference in densities between the oil and gas phases. The exponents of these power laws are "universal," whereas the prefactors vary between gas/oil systems. This allows the classification of the most common injection gases with respect to their efficiency in reducing the gas/oil IFT. This efficiency increases with the miscibility of the injected gas in the oil: supercritical CO2 is more effective in reducing IFT than off-critical CO2 or CH4, which themselves are more effective than N2.

A simple procedure is then introduced to determine the wetting (or spreading) behavior of oil on a porous substrate covered with water, as often occurs in practice. The only inputs required are the composition and densities of the three coexisting phases: water, oil, and gas. When they are not measured, these quantities can be calculated by means of an appropriate equation of state. CO2 turns out to be the most effective for promoting the spreading of the oil on water, followed by CH4 and then by N2.
Predicting Permeability From Well Logs in Carbonates With a Link to Geology for Interwell Permeability Mapping
Authors: Jennings James W. , Lucia F. Jerry
Published: December 2007

This paper presents a model to estimate permeability from well logs in carbonate reservoirs. The model relates permeability to interparticle porosity, makes special accommodation for separatevug porosity, and includes a rock-fabric classification scheme with an important dual petrophysical-geological significance. The dual significance of the rock-fabric classification provides an important link to geological models for use in distributing permeabilities between wells. Porosity and permeability are highly variable and are difficult to predict spatially in most carbonate reservoirs, but rock-fabric changes tend to be organized systematically within a sequence stratigraphic framework.
Theory and Analysis of Injectivity Tests on Horizontal Wells
Authors: Peres Alvaro M. M. , Reynolds Albert C.
Published: December 2007

This work presents information on the pressure behavior at a horizontal water-injection well completed in an oil reservoir. We show that, quite remarkably, the pressure and pressure derivative behavior is similar to that of the single-phase solution calculated with oil properties evaluated at initial water saturation. This behavior is quite different from the injectivity solution for a vertical well where, except at early times, the injectivity solution is similar to the single-phase solution based on water properties. It is shown that flow regimes can be identified with the standard log-log diagnostic plots. The Thompson-Reynolds steady-state theory for multiphase-flow well testing is applied to derive a simple accurate approximate analytical solution for the wellbore pressure during injection for both the horizontal and vertical well cases. The horizontal well solution is completely new. Unlike the previous solutions for the vertical well case, we have incorporated a skin zone based on Hawkins' formula. The analytical solution, verified by reservoir simulation results using hybrid grids and local grid refinement, shows that the movement of injected water in a damaged zone has a strong and distinctive effect on both the pressure and pressure-derivative behavior at early times. Based on the analytical solution, we propose procedures for analyzing pressure data from injectivity tests.