bluuebunny/crossref_metadata_2025 huggingface dataset:
Permeability Modification Using Sulfomethylated Resorcinol-Formaldehyde Gel System
Authors: Zhuang Y. , Pandey S. N. , McCool C. S. , Willhite G. P.
Published: December 2007

A gel system based on the reaction of sulfomethylated resorcinol and formaldehyde has been developed. This gel system, termed SMRF, is tolerant of a wide range of salinities and divalent ion content. It has been tested in laboratory core floods conducted at 41°C(105.8°F) using Berea sandstone cores, Baker dolomite cores and reservoir rock from the Pen Field which produces from the Lansing-Kansas City formation. In these core tests, the gelling system was injected into short cores and allowed to gel in situ. Permeability to brine after in situ gelation was determined for each core as well as permeability after several pore volumes of brine injection. The SMRF gel system reduced the permeabilities of Berea and Baker dolomite cores to values on the order of 8–18 microdarcies. The Lansing-Kansas City reservoir rock was plugged by the gel system.

The new gel system has a viscosity close to water when the reactants are mixed and is easily injected into porous rock. SMRF forms strong and stable gels at temperatures between 25°C and 52°C(126°F) and in the pH range between 5 and 8.0. Gel times are a function of pH, salinity, concentration of the chemical constituents and temperature, and can be controlled by appropriate adjustment of these parameters. Laboratory data describing the characteristics of the SMRF system in beaker tests are presented. Also included are results of extensive core testing.

The SMRF gel system is one of the few gel systems that will form a gel in situ in the presence of the strong buffering that occurs when brine is injected into carbonate rock. The SMRF system has potential for near wellbore treatments of carbonate matrix rock such as found in the Lansing-Kansas City formations of central Kansas as well as the low permeability carbonates found in the San Andres formations in West Texas.
The Unexpected Advantages of a Temporary Fluid-Loss Control Pill
Authors: Hardy Mary
Published: December 2007

This paper describes the chemical theory behind the unexpected features of an environmentally acceptable temporary fluid-loss control pill. This liquid gel concentrate pill meets EPA and OSPARCOM standards for use in on- and offshore operations, and has been used for a variety of applications throughout the world.

Economic reasons and environmental regulations compelled one oil-service company to find a replacement for an existing field product. Initially, research was aimed toward the development of a pill that had the following characteristics.

It blocks fluid flow into and out of the wellbore. It is mixable in brines 8.35 to 19 lb/gal. It can be used effectively at temperatures as high as 257°F/125°C.

Researchers concentrated their efforts on optimizing the synthesis, manufacture, and field-mixing procedures pertaining to a replacement crosslinkable hydroxyethyl cellulose fluid (RXHEC). RXHEC degrades by uncrosslinking and unzipping the backbone, which simplifies the disposal of returns. It is capable of breaking with weak acids, which allows the use of external breakers in acid-sensitive wells. The first field application took place in May 1993. Since then, some evidence has revealed additional features that were not conceived in the initial design.

Dispersion occurs with no "fish-eyes." Crosslinking occurs with most metals and non-toxic metals. The fluid can be pumped fully crosslinked. Reversible shear degradation of crosslinked RXHEC fluids allows good fluid-loss control. Tubulars slip through the RXHEC pill with little difficulty, making a remedial pill unnecessary. The RXHEC pill remains in place during tripping and retrieving operations. It is indefinitely stable to 275°F/135°C.

Laboratory data and field data are presented. Chemical explanations for the unexpected features are discussed in detail.
Permeability Reduction by Treatment with KUSP1 Biopolymer Systems
Authors: McCool C. S. , Green D. W. , Willhite G. P. , Shaw A. K. , Bhattacharya S. , Singh A.
Published: December 2007

KUSP1 is a polysaccharide that is derived from a particular bacterium that was discovered at the University of Kansas. Unique properties of KUSP1 were the incentive to investigate the application of this polymer for use in permeability-modification treatments. KUSP1 dissolves in alkaline waters but forms a gel as the pH of the solution is lowered to values below 10.8. Two methods to reduce the pH of KUSP1 solutions were studied. An ester was utilized to trigger gelation. Monoethylphthalate ester (MEP) reacts with water to produce an acid. The second method relied on the interactions between the alkali polymer solution and the rock material to reduce the pH. The performance of the KUSP1-MEP system and KUSPl-rock system was studied in several types of porous media.

A second property of KUSP1 is that it can be gelled in a time-delayed manner by the addition of boric acid. Performance of the KUSP1-boric acid system was studied in sandpacks and Berea sandstone cores.
A New Method for Systematic Identification of Nontoxic Gels
Authors: Kolnes Jostein , Saurdal Janne , Nilsson Svante
Published: December 2007

A new method for systematic identification of nontoxic gels is described. It is based on fundamental chemical reactions between organic compounds containing different functional groups, here called X and Y. Such reactions are found in most textbooks on organic chemistry. The next step is to identify polymers with either X or Y as a functional group. The crosslinker can than be selected from a usually large group of molecules containing at least two X groups (for the Y polymer) or at least two Y groups (for the X polymer).

Using catalogues listing the toxicity of organic chemicals, both the polymers and crosslinkers can be screened, and the least toxic and least costly can be selected for further studies. In these studies the gelant can be optimized regarding gelation time, including the effect of pH and temperature, gel appearance as a function of concentration of both polymer and crosslinker, and the behavior of the gelant and gel in cores.

In this study we report results from experiments carried out on gelant systems based on the ester reaction between a carboxylate group (X) and an alcohol group (Y). Here both polymers containing carboxylate groups (hydrolyzed polyacrylamide) and alcohol groups (polyvinylalcohol) can been used. The corresponding crosslinkers are di- and polycarboxylic acids (X) and di- and polyols (Y). This paper focuses on the system polyvinylalcohol and polycarboxylic acids.
Investigation and Improvement of BaSO4 Scale Inhibition Tests
Authors: Yuan M. D. , Anderson M. , Jamieson E.
Published: December 2007

The commonest means of laboratory evaluation/screening of scale inhibitors for oilfield applications is by conducting scale inhibition jar tests. This paper focuses on several aspects concerning barium sulphate scale inhibition jar tests and highlights three particular factors which may influence the test outcome and the ranking of an inhibitor's performance as compared with others. The work presented in the paper confirms the critical importance of temperature. It proves that filtration of a supernatant sample when taken from the test jar for Ba analysis could lead to erroneous results on barium sulphate inhibition efficiency. This investigation also indicates that chelating agents may reduce inhibitor inhibition efficiency against barium sulphate. However, such an effect is found to be far less significant than that reported elsewhere.
Experiments and Computer Analysis Show How Perforators Damage Natural Fractures
Authors: Halleck Phillip M. , Dogulu Y. Serdar
Published: December 2007

Numerical modeling has been used to analyze the results of a series of perforation flow experiments in fractured rock. Perforating across the fracture reduced conductivity by 75% in oil-saturated samples and 83% in gas-saturated samples. In both cases, single individual tests showed large increases in fracture conductivity, showing that the mechanisms involved are subject to random factors. More important, flow into the perforation is only ~40% (44% in oil-saturated samples and 38% in gas saturated samples) of that calculated from post-shot fracture conductivity. This suggests some combination of perforation tunnel plugging and sealing of the fracture near the perforation.

Cylindrical samples of a 1-mD tight sandstone, containing a saw-cut fracture, were perforated with a conventional oil-well perforator under simulated down-hole pressure conditions. The flow impedance through the fracture was measured before and after perforating, and flow rate out through the perforation was also measured after perforating. Analysis of the results was performed using two numerical models to simulate matrix and fracture flow. These models were used to calculate the change in effective fracture conductivity caused by perforating and to predict flow out through the perforation.

Post-test examination of the samples by visual and X-ray CT analysis show that shock stress resulting from penetration of the shaped charge jet causes deformation of the rock near the perforation tunnel, sealing the fracture where it intersects the perforation. This mechanism is a newly recognized form of formation damage specific to fractured formations. Underbalance conditions up to 5.0 MPa (750 psi) were not sufficient to clean the perforation or the perforation-fracture junction. Jet metal can also invade the fracture if the intersection is near the tip of the perforation where the jet velocity is low. This effectively shortens the usable penetration depth. These effects will be present despite efforts to ensure adequate penetration and to prevent fluid loss.
Fracture Optimization eXpert (FOX) - How Computational Intelligence Helps the Bottom-Line in Gas Storage; A Case Study
Authors: Mohaghegh Shahab , Hefner M. Hugh , Ameri Sam
Published: December 2007

Just like any other industry, the bottom-line in gas storage is economics. Any tool, new or old, conventional or unconventional, is evaluated by its contribution to the bottom-line. Fracture Optimization eXpert (FOX) is a new software tool that has been developed using the cutting edge of information technology, namely Computational Intelligence. Two different paradigms of Computational Intelligence was used in development of FOX. They are Artificial Neural Networks and Genetic Programming.

What distinguishes FOX from conventional frac simulators (Frac-pro, …) is its unique capability to A) not only predict post-frac deliverability but also B) suggest the best possible combination of frac parameters for optimum results. Furthermore, FOX is able to do this using only historical (production / injection) data and well completion data. In other words, FOX can do without reservoir data such as porosity, permeability, and stress profile data that are an essential part of any conventional approach.

In this paper FOX is applied to a gas storage field in north eastern Ohio (Clinton Sand). The accuracy of its post-frac deliverability prediction is demonstrated. Using only available historical data optimum frac jobs are designed and the improvement of post-frac deliverability is calculated. A cost - benefit analysis is performed to show the advantages of using this method when compared to conventional approach.

FOX can help the bottom-line by eliminating the need for expensive data collection processes such as well tests, coring,…., while its predictions of post-frac deliverability has a high accuracy. Furthermore, even if such data is available for a field, conventional frac simulators only provide frac job outcome for any particular design, planned by engineers. They are not able to optimize the frac treatment procedure to get the best possible result for any individual well, a capability that makes FOX unique.
Estimation of Turbulence Coefficient Based on Field Observations
Authors: Kelkar M.G.
Published: December 2007

Isochronal testing is commonly used to evaluate the performance of gas wells. This paper proposes a new technique to estimate the value of turbulence coefficient based on isochronal tests. The proposed method is easy to apply and evaluate. Further, the method also provides a value of bg under stabilized conditions which can be used to predict the performance of gas wells under stabilized conditions.

The proposed method is validated using field data under a variety of operating conditions. The values of turbulence coefficient based on the field data can differ significantly compared to the literature correlations. This further shows the importance of obtaining appropriate reservoir parameters based on the field rather than the lab data.

Introduction

The use of isochronal or modified isochronal testing is well established in the gas industry. These tests are common for gas wells which take a long time to reach a stabilized rate. A common example would be a low permeability, fractured reservoir. Instead of testing these wells till a stabilized rate is reached, the wells are tested for a fixed period of time and the bottom hole pressure is measured. For isochronal testing, the well is then shut in till it reaches a stabilized pressure and the procedure is repeated for different rate. For modified isochronal testing, the well is shut in for a fixed period of time, and the shut in pressure is measured at the end of that period. The procedure is then repeated at other rates.

By repeating this procedure for different time intervals, we can gather information about rate versus pressure drop in the formation for these time intervals. Ultimately, using this information, our goal is to establish an appropriate rate versus pressure drop relationship under stabilized conditions.

Two procedures are commonly used to establish the equation for rate versus pressure drop. An empirical method states that,

(1)

where qg is the gas rate, C and n are constants and p and pwf are average pressure and bottom hole pressure respectively. We can write a simpler equation in terms of pseudo-real pressures as,

(2)

where m(p) and m(pwf) are pseudo-real average pressure and pseudo-real bottom hole pressure respectively.

Under transient conditions, the value of C is not constant. Instead, we can write Eq. 2 as,

(3)

where c(t) represents a term which is a function of isochronal interval t. In literature, methods are proposed to estimate the value of C corresponding to stabilized rate based on the transient state information −C(t). See e.g., Hinchman et al. In that paper, Hinchman et al. propose that be plotted as a function of log t, and the line be extrapolated till t is equal to the time it takes to reach stabilized state period. P. 223^
Continuous-Flow Gas-Lift Installation Design Based on Decreasing Production Rate with Required Increased Depth of Lift
Authors: Winkler H. W. , Maier H.
Published: December 2007

A continuous-flow gas-lift installation design for injection-pressure-operated gas-lift valves is outlined on the basis of tubing capacity and daily injection-gas rate. The maximum daily production rate by gas lift decreases with a required increase in the depth of lift. The reservoir inflow performance of the producing formation is not considered in the installation design procedure. This valve spacing method is suited for gas-lift installations in wells with unknown productivity and/or changing reservoir pressure.
Controlling Liquid Load-Up with "Continuous Gas Circulation"
Authors: Boswell J. T. , Hacksma James D.
Published: December 2007

abstract

"Continuous Gas Circulation" (CGC) is a new method of controlling liquid load-up in gas wells. CGC uses a compressor to continuously circulate the wellbore gas (down the tubing-casing annulus and up the tubing), increasing the velocity of the gas flowing up the tubing. The higher velocity carries liquid to the surface and prevents an accumulation in the wellbore. Accumulating liquid increases the hydrostatic gradient, increases backpressure on the formation and reduces production.
Continuous-Improvement Stimulation Program Generates Excellent Results in the Morrow Sandstone of the North Texas Panhandle
Authors: Harrington T.R. , Lehman L.V. , Bowman M.
Published: December 2007

This paper illustrates a process that allowed the operator to optimize production by placing large concentrations of proppant in the Morrow Sandstone in the North Texas Panhandle. This process first consisted of analyzing data and results from previous Morrow fracture stimulations within the study area, but it soon proressed to optimizing pad volume percentage, proppant grade, perforation scheme, frac fluid selection, and other critical factors over a four-well stimulation project. Initial efforts placed 8 lbm/gal of proppant; by the end of the project, 19.8 lbm/gal were being placed. Stimulation practices developed through this continual improvement process provided more cost-effective results.

This paper illustrates the challenge to place extreme concentrations of proppant in face of a high leakoff environment. This process required the use of an advanced, real-time, three-dimensional (3D) frac model to monitor prefrac calibrations and, in some cases, redesign the treatment to accommodate the leakoff field. Fracture stimulation quality control played a key role in these efforts.

Introduction

The Morrowan Series in the western Anadarko Basin is commonly divided into the Upper Morrow and Lower Morrow formations. Production from both formations is from relatively clean, porous sandstones that comprise some of the most prolific producing gas reservoirs in the Texas and Oklahoma panhandles. Average initial production rates are 3 MMscf/D, with ranges from 0.1 MMscf/D to 21 MMscf/D. To date, the average gas recovery per well is 1.5 Bcf, with ranges between 0.1 Bcf to 8 Bcf. All Morrow wells within the study area are less than 15 years old, and 56% have produced for less than 5 years. These high initial rates are possible with average permeabilities between 5 to 5 md.

The inherent dry-hole risk of both formations can be attributed to the discontinuous nature of Morrow sand deposition. Lower Morrow sands are generally marine barrier/offshore sands deposited parallel to paleo shoreline trends. Within the study area of NE Sherman and NW Hansford Counties (Fig. 1), production typically occurs only at the updip termini of these sands. Upper Morrow sands are fluvial.1 These sands are deposited as discrete point bars within a broader valley system, resulting in a semilinear trend of segregated reservoirs. Only 34% of the Morrow exploration and development tests in the study area encountered productive Morrow.

Morrow fracture stimulation technology has grown dramatically over the past 15 years. In the early 1980's, fracturing jobs were conducted with gelled 3% acid and sand concentrations that rarely exceeded 1.5 lbm/gal. Energized fracturing jobs with N2 and CO2 foams, then became the norm, even in nondepleted wells, because of the nondamaging nature of these fluids. Job schedules were more aggressive, but sand concentrations rarely exceeded 4 lbm/gal.
Use of Acoustic Surveys for Field Calibration of Surface Readout BHP Gages in ESP Installations
Authors: McCoy J. N. , Podio A. L. , Rowlan Lynn , Garrett Mark
Published: December 2007

The use of surface readout BHP gages in ESP systems has become more prevalent with the development of cost effective installations. In spite of the improvement in their reliability, the BHP pressure sensors are subject to zero drift during their operational life. It thus becomes necessary to periodically check the indicated pressure and adjust its value to eliminate the zero shift. Since it is not economically justifiable to pull the tubing and the sensor, a method has been developed and field tested that permits to make the calibration check from surface measurements.

In an operating well, the method requires the periodic measurement of annular surface pressure using a pressure transducer with an accuracy of 0.1% and acoustic fluid level depth digitally acquired with a resolution of one millisecond while the casing valve is closed and produced gas is accumulating in the annulus. As fluid enters the wellbore the liquid is produced through the pump while the gas accumulates in the casing annulus. A software program determines the density of the gas in the annulus and computes the pressure at the gas/liquid interface accounting for the effect of the gas column hydrostatic. The process is continued until the gas/liquid interface is displaced near the pump intake, at which point the computed bottom hole wellbore pressure should be very close to the pressure indicated by the surface readout. Any discrepancy between the two measurements is used to estimate the zero shift and to correct the surface readout.
Effective HCl Diffusion Coefficients From Correlations of HCl-Limestone Reactions
Authors: Mumallah Naim A.
Published: December 2007

Hydrochloric acid solutions were reacted with limestone core plugs using an annular flow reactor at acid-fracturing conditions. The obtained reaction rates were correlated with theory using a correlation that was recently verified to be suitable for correlating HCI reaction rate with mass transfer parameters. Applying the correlation to the present data produced effective diffusion coefficients for HCI from the different acid solutions at acid-fracturing conditions. The results showed that the diffusion coefficient of an acid solution made in distilled water was larger than the diffusion coefficient of an acid solution made in synthetic North Sea water. The diffusion coefficient of a retarded acid was found to be an order of magnitude smaller than the diffusion coefficient of neat acid.
Kinetics of the Primary Reaction of HF on Alumino-Silicates
Authors: Gdanski Rick
Published: December 2007

The standard description of HF-acidizing chemistry clearly demonstrates a primary and secondary reaction of HF with alumino-silicates.1 Field experience has taught our industry that possible precipitation during the secondary reaction can ad-versely affect treatment success,2 especially in formations with high K-feldspar content or temperatures above 300°F. Recent work has also reported the existence of a third, or tertiary reaction of HF with alumino-silicates.3

This paper reports the determination of the rate law and kinetics for the primary reaction of HF on sand, clay, and feldspar over a broad temperature range. The rate law for the primary reaction of HF with sand had no HC1 dependence and was second-order in HF concentration. The rate law for the primary reaction of HF with clay and feldspar was assumed to also have no HC1 dependence and was adequately described by a first-order in HF concentration. In addition, a mass transfer equation for reactive fluids flowing through porous sandstone media is proposed. These findings were made possible by recently applied experimental techniques including 19F NMR Spectroscopy,3 fractional pore-volume flow experiments4 and an accurate knowledge of the HF stoichiometry.5 Laboratory findings have been verified through detailed analyses of flowback samples from field treatments.6
Field Evaluation and Optimization of Matrix Acidizing Treatments
Authors: da Motta E. Ponce , dos Santos J.A.C.M. , Zhu D. , Hill A. D.
Published: December 2007

In a matrix acidizing treatment, it is extremely important that the appropriate acid formulation be used, that no damage be left in the reservoir, and that no excess acid be injected. Nowadays, this can be easily accomplished with the aid of computerized real-time monitoring techniques, which provide on-site evaluation of the stimulation results.

We applied a real-time monitoring technique to a series of acidizing treatments to evaluate stimulation performance and to optimize subsequent treatments in the same area. From the measured surface pressure and injection rate, a computer program calculated the bottomhole pressure and estimated the skin factor as the treatments progressed. In this way, the responses of the wells to stimulation were evaluated. Real-time monitoring of the evolving skin factor showed when further acid injection resulted in no further stimulation, leading to reduced acid volumes in subsequent treatments.

By applying this real-time monitoring method, we have improved acidizing practices in two fields, located in the northern part of Brazil. In a series of injection well treatments, acid volumes were reduced by 25% from standard practice, with no loss in acidizing efficiency. We were also able to change one of the acid compositions from regular mud acid to a more compatible 6% HC1/1.5% HF.

In more sensitive production well treatments, the real-time monitoring of skin factor may be even more useful by ensuring total damage removal or in identifying deleterious effects of overtreatment More importantly, this technique will also indicate when design changes such as increased acid volume, different acid formulation, or different injection rate schedule are needed to reach the treatment objectives.
Optimization of Stimulation Treatments for Improved Oil Recovery in Complex Lithological Reservoirs
Authors: Yao C. Y. , Squyres J. W. , Baycroft P. D.
Published: December 2007

Well stimulation normally consists of matrix acidizing, acid fracturing and proppant fracturing. The optimum stimulation treatment depends on both reservoir characteristics and the formation damage mechanism. The oil recovery can be improved with successful stimulation treatments.

This paper presents a case study of a pilot stimulation project in the Onbysk oil field in Tatarstan, Russia. The objective of this project was to optimize stimulation treatments in geologically complex reservoirs for the improved oil recovery. The Onbysk field consists of seven stacked reservoirs with a complex lithology of shaly sandstone and limestone with microfractures. Different stimulation techniques have selective applications to different reservoirs for improved oil recovery. The improved oil recovery has been evaluated using production history data and decline technique.
An Experimental Investigation of the Diversion Characteristics of Foam in Berea Sandstone Cores of Contrasting Permeabilities
Authors: Siddiqui S. , Talabani S. , Yang J. , Saleh S. , Islam M. R.
Published: December 2007

Foam has been used successfully in the field as a diverting agent for matrix acidizing when layers of contrasting permeabilities are present. However, the mechanisms governing the diversion performance of foam are still not properly understood and only a limited number of foam diversion papers can be found in the literature. This paper discusses the results from several dual-core experiments using 11- and 22-inch long and 1.5-inch diameter fired Berea sandstone cores (permeability range: 10 to 1000 md) in which parameters such as foam quality, total injection rate, foam slug size, etc. are varied systematically for different permeability contrasts. Each experiment consists of a gas-free surfactant injection phase, followed by a foam injection phase, which is then followed by a brine injection phase simulating the post-foam acid injection stage. The pressure data along each core at four locations and the weight of the liquid effluents for each core are recorded continuously. An attempt is made to quantify the diversion performance by the introduction of various diversion factors. The effect of each of the variables such as foam quality, injection rate, slug size etc. on the diversion factors are then compared for different permeability contrasts. Results show strong dependence of the diversion performance on permeability contrast, foam quality and total flow rate. This study provides important guidelines for designing acid jobs for different permeability contrasts and ranges when foam is used as a diverting agent.
Water Cone Histeresis and Reversal for Well Completions Using the Moving Spherical Sink Method
Authors: Shirman E. I. , Wojtanowicz A. K.
Published: December 2007

Presented in this paper is a theoretical and experimental study of water cone development and reversal. The theoretical study employed a new analytical method, called moving spherical sink model (MSSM), for accurate modeling of flow in the vicinity of a limited-entry well in a heterogeneous (kv,kh) reservoir. In contrast to other analytical models, MSSM does not lose validity in the near-well zone. It calculates pressure precisely at and outward from the borehole surface. This high resolution of MSSM in well's vicinity enables studying flow mechanisms that have been beyond competence of conventional models such as pressure distribution outside well's completion and development and reversal of water coning.

The results of this water coning study show that for oil production rates below critical (breakthrough) rate there are two equilibrium shapes of the water cone: lower (stable), and upper (unstable). Also shown is a hysteresis of the water cone height development and reversal caused by the increase – decrease scheme of production rate. The paper explains why reversing the cone is difficult because it requires reduction of production rate much below its critical value. It also describes how to determine the water cone reversal rate.

The experimental part of this study provides verification of the theoretical findings using a physical model. The results, summarized in this paper, showes all four stages of the water cone histeresis: from equilibrium cone buildup with increased production rates, to stability loss followed with water breakthrough at critical production rate, to continuing water breakthrough in spite of decreasing production rates, to water cone reversal at very low value of the reversal production rate.

This study provides basic understanding of stability mechanisms that control three-dimensional water coning. It also provides an analytical method for finding the cone reversal production rates.
Asphaltene Deposition During CO2 Flooding: A Laboratory Assessment
Authors: Srivastava Raj K. , Huang Sam S.
Published: December 2007

In a CO2 miscible displacement process, the injected CO2 solvent can induce flocculation and deposition of asphaltenes and other heavy organic particles. This can cause numerous production problems with a detrimental effect on oil recovery. Therefore, it is important to understand the behavior of this organic matter under reservoir operating conditions. This paper presents results of dynamic and static precipitation tests conducted at reservoir temperature and pressure conditions to investigate the likelihood of asphaltene deposition problems in the Weyburn reservoir (in southeast Saskatchewan). A laboratory study using a high-pressure PVT cell was undertaken to determine the effect on asphaltene flocculation/precipitation of operating pressure, CO2 concentration, gas contaminants in CO2, and presence of formation brine for three different oil samples collected from the reservoir. The extent of asphaltene deposition was also assessed through coreflood experiments using preserved and restored reservoir core material collected from different reservoir zones of increasing permeability (Marly, Vuggy, and high-grain-size Vuggy) and through a suitably designed X-ray CAT-scanning visualization experiment.

Static tests indicated the most important factor on which the asphaltene precipitation depended was the CO2 concentration. For oils belonging to the same pool, the increase in asphaltene precipitation with solvent concentration was proportional to the initial asphaltene contents of the oil. Coreflood experiments showed a considerable increase in asphaltene deposition in the core matrix following CO2 injection. Pore topography of the core matrix played an important role in the extent of CO2-induced asphaltene deposition. The deposition appeared to be higher in a high-grain-size Vuggy matrix than in the normal Vuggy matrix, and lowest in the Marly matrix. X-ray CAT-scanning tests depicted localized areas of asphaltene deposition along the length of the core, with significant deposition suspected to be occurring near the inlet of the core. The CAT-scan tests also identified sites of suspected formation damage to the core matrix associated with CO2 injection.
Diffusion Of Gas In Oil Based Drilling Fluids
Authors: Bodwadkar S. V. , Chenevert M. E.
Published: December 2007

Background gas has been observed in oil based drilling fluids in contact with gas bearing formations. It has been postulated that such background gas is caused by diffusion. The objective of this study was to quantify the transport of gas by diffusion. The effect of filtrate flow into the formation (against the gas transport) has been evaluated.

The diffusion coefficients of the filter cakes were determined in the laboratory at various temperatures and pressures. The significance of diffusion was mostly decided by the rate of filtration. The flux of gas by diffusion drops sharply at some threshold value of pressure differential in the wellbore, irrespective of the temperature.
Cautious Utilization of Formation Micro-Imaging Logs
Authors: Fitzsimmons Fitzsimmons , Wadleigh Wadleigh , Curran Curran , Kacir Kacir
Published: December 2007

Resistive imaging logs (FMI and EMI) have been embraced by those challenged to characterize flow properties of massive carbonate reservoirs. These logs provide valuable insights for assessment of in situ heterogeneities but are not intended to directly indicate those features that provide the best connections between the wellbore and the formation. High resolution flow surveys of openhole completions in massive carbonates can offer a glimpse of flow capacity that has not suffered cement and perforation damage related to cased completions. Accurate reservoir description can only be accomplished by distinguishing between those features that are effective flow conduits and those that simply appear as large anomalies at the wellbore.
Dynamic Fluid-Loss Studies in Low-permeability Formations with Natural Fractures
Authors: Vinod P. S. , Flindt M. L. , Card R. J. , Mitchell J. P.
Published: December 2007

Dynamic fluid loss through low permeability formations with natural fractures was experimentally investigated in a high-pressure, high-temperature dynamic fluid-loss cell to understand the effectiveness of particulate fluid-loss control additives. The study focused on understanding the relationship between the size distribution and shape of the fluid loss control material on leakoff control and on the cleanup potential.

Sandstone cores of 1-in. diameter and 3-in. length and of approximately 0.05 md were cracked on a press to simulate the naturally fractured low permeability formation. The effective permeability of the fractured cores varied from approximately 0. 05 to 2 md. The effective permeabilities of the fractured cores were measured in situ before and after the leakoff test to quantify damage caused by the external and internal filter cake formation. All tests were conducted at 150°F with linear and borate- or zirconium-crosslinked guar solutions and gels. The wall shear rate across the face of the core was varied by changing the flow rate to simulate a typical fracture shear history at the leakoff face. The core and cell were left overnight at the confining pressure (1500 psi) and temperature before flowing back with brine.

It was found that low-permeability formations with natural fractures have characteristics very similar to those of high-permeability formations. Crosslinked fluids not only are good in reducing fluid leakoff, but also provide higher matrix retained permeability than those obtained with linear polymer solutions. The concept of leakoff control effectiveness, which depends on the leakoff control characteristics and the final cleanup potential, is introduced to quantify the depth of invasion of the polymer (internal filter cake) in the core. The leakoff control effectiveness was used as a tool to compare the relative performances of various fluid-loss additives. The results show that the shape as well as the size distribution of the fluid-loss additive can have a significant impact not only on leakoff control but also on cleanup potential.
Economic Analysis of Horizontal Wells
Authors: Osisanya Samuel O.
Published: December 2007

Horizontal drilling technology has become an economic reality, and the result has been a dramatic upsurge in the number of horizontal wells being drilled. Horizontal wells have proven to be cost effective in optimizing hydrocarbon recovery. Although the majority of wells were drilled because of expected productivity increases, they have not always been a solution to the economic success of the project. As the industry's experience of drilling, completing, and producing horizontal wells increases, so does the realization that horizontal well technology is not always a solution to the problem of more cost effective production. Economic analysis of horizontal well projects are much more complicated than that of vertical well projects because of the many variables involved. Several parameters are evaluated for the economic success of horizontal well projects. These include drilling and completion options, hydrocarbon pay zone thickness, well spacing, fracture intensity, vertical communication, formation damage, and multiwell prospect. The total well cost for the horizontal well is divided into two components: the vertical section cost and the horizontal or lateral section cost. The horizontal or lateral section cost is strongly time-dependent. The type of completion also affects horizontal well performance, and certain completion options are only possible with certain drilling techniques.

This paper presents a step-by-step procedure that can be used when performing an economic analysis of a horizontal well project. The analysis is based on cost estimates associated with all phases of the project. To ensure the economic success of a horizontal well program, multi-disciplinary efforts are required in all preplanning phases of the program. This includes obtaining pertinent information before the well is actually drilled, with a post review of the program after production has been established.
Comparison of the Performance of a Horizontal Dead-End Tee Steam Splitter to a Horizontal Ring Steam Splitter
Authors: Chandler P. J. , Thomas C. A.
Published: December 2007

Mobil Exploration and Producing U. S. ("Mobil") currently uses two different types of steam splitter devices to divide the main steam supply among the steam drive injection wells. The steam splitter's job is to take an incoming stream and divide it into several smaller streams of approximately equal steam quality. The performance of a horizontal dead-end tee steam splitter was compared to a horizontal ring steam splitter to determine which type of splitter did the best job of providing equal quality splits. Performance data from both splitters were taken using a portable test separator while each splitter was in service. The test data show that both splitters provide roughly equal splits among their wells and that neither splitter has a performance advantage. Cost and operating data is presented which will aid the decision as to which type of splitter is appropriate for a given steamdrive project.
Visualization of Steam Injection in Fractured Systems Using Micromodels
Authors: Haghighi M. , Yortsos Y.C.
Published: December 2007

We present visualization studies of hot water and steam injection in micromodel geometries that mimic a matrix-fracture system. Emphasis is placed on the matrix-fracture interaction during steam injection. We visualize the movement of steam and determine the conditions under which matrix penetration by steam occurs. More generally, the effectiveness of steam injection in displacing oil from the matrix is assessed.

Displacement of oil was observed to occur by three mechanisms: a thermally-induced solution gas-drive, capillary imbibition of condensed water and displacement by steam, when the latter penetrated the matrix. Vaporization of light components at elevated temperatures generated an efficient solution-gas drive in the matrix, without the need for steam penetration. This also led to the formation of stable foam-like lamellae, which improved oil production by blocking the movement of steam and water in the fracture. This mechanism was also found to apply during hot water injection. Condensed water imbibed the matrix according to rules that govern imbibition of a fracture-matrix system. Steam penetration of the matrix occurred when the steam rate exceeded a critical value, determined from drainage considerations. The results should be useful in modeling of steam injection in naturally fractured reservoirs.

Introduction

Steam injection is an effective method for the recovery of heavy oil worldwide (Prats, 1982). Steam injection can also be used to recover light crudes, with an efficiency that approaches under certain conditions that of waterflooding Naturally fractured reservoirs are estimated to contain 25-30% of the world supply of deposits (Saidi, 1988). Although of potentially high importance, the application of steam injection in fractured systems, however, is not widely applied.

There exist some obvious differences between displacements in homogeneous and in fractured media. Unlike homogeneous reservoirs, in fractured systems the injected steam does not necessarily sweep uniformly the porous media, but may preferentially flow through the high-conductivity fractures. Furthermore, the mechanism of heating in fractured reservoirs is mostly by conduction, while in a homogeneous system heat is transferred mainly by convection. Therefore, steam injection recovery mechanisms can be quite different in fractured media. Experimental and numerical studies to understand steam injection in fractured systems have been conducted by various investigators. Below, we summarize the most important findings.

Reis (1990) provided a comprehensive review of oil recovery mechanisms in steam injection in fractured reservoirs. Thermal expansion and gas generation were described as two key mechanisms. In the first, the expansion of fluid and rock minerals at high temperatures result in the expulsion of fluids from the matrix to the fracture. A differential thermal expansion of the order of 0.05%/ F was estimated by the combination of porosity reduction and fluid expansion. P. 67
More Oil from Better Information: New Technological Applications for Testing Producing Wells
Authors: Christianson Bruce A.
Published: December 2007

Producing Operations are developing advanced tools in response to the challenge of maximizing oil recovery and minimizing operational costs. Oil and water volumes from producing wells are measured by well gauge systems. Poor gauge system performance can mask true well output, at the expense of well optimization decisions.

In Texaco's Bakersfield Division, two statistical analysis techniques, Process Capability Index (PCI) and Confidence, are being used to improve gauge systems so that true well performance can be analyzed.
Compositional Input for Thermal Simulation of Heavy Oils With Application to the San Ardo Field
Authors: Lolley C. S. , Richardson W. C.
Published: December 2007

Significant compositional changes have been recently documented in laboratory analyses of remaining oil in core samples from mature steamfloods. In order to properly account for these changes, the production of hydrocarbon condensate (casing blow) from heavy oil reservoirs, and the formation of an in-situ solvent bank, a fully compositional, equation-of-state approach in thermal reservoir simulation is needed. Dead oil thermal simulation will not account for these recovery mechanisms.

A survey of equation-of-state development for lighter oils reveals that traditional methodologies using a C7+ heavy split with a gamma distribution and α=1 may not be correct for some medium to heavy oils. Extensive gas chromatography (GC) analyses reveals a "double hump" or bimodal compositional distribution in some medium to heavy oils. This bimodal distribution is often overshadowed in lighter oils due to increased presence of C1-C6 components. Because of this bimodal distribution and absence of significant C1-C6 composition, a different methodology and series of laboratory test must be used to develop equation-of-state parameters as well as account for complex interactions between polar water molecules and non-polar hydrocarbon molecules which occur in the process of steamflooding. This data is then used to tune equation-of-state parameters for use in compositional thermal simulation. This new technique is presented as an alternative model for EOS parameter development for medium to heavy oils and is more economical than previous methods which require a full ASTM-2892 distillation. San Ardo crude oil (120API) is used to demonstrate the technique. The full 40 component model can then be pseudoized into fewer components for field scale simulation.
Improving HPHT Stability of Water Based Drilling Fluids
Authors: Oort Eric van , Bland R. G. , Howard S. K. , Wiersma R. J. , Roberson Loyd
Published: December 2007

A new method is discussed to improve the HPHT stability of conventional rheology modifiers and fluid loss polymers used in water-based drilling fluids. The method exploits the interactions of polysaccharides (e.g. xanthan gum, scleroglucan), cellulosics (e.g. CMC, PAC) and starches with polyglycols. Polymer and polyglycols were found to associate by inter-molecular hydrogen bonding and hydrophobic interactions. This association / complexation was found to stabilize the polymers at higher temperatures. Our laboratory findings are validated by field observations in the Kakap field in Indonesia that show improved HPHT stability when adding polyglycols to water-based drilling fluid formulations.
Optimization of Multiple Bit Runs
Authors: Barragan R. V. , Santos O. L. A. , Maidla E. E.
Published: December 2007

Optimization of single bit runs to achieve the minimum cost per meter has been discussed and published quite extensively throughout papers, journals, and other periodicals. Very little has been said and done concerning multiple bit runs that is the case for over 90% of the wells drilled worldwide. The reason for this is that the problem is much too complex to be solved with a set of analytical equations due to the interdependence of some of the drilling model coefficients, the uncertainties associated with the parameters involved such as the rock type, strength and mechanical properties, and a good handle on the historic operating conditions and bit grading.

A research program was commissioned to address this based on an heuristic approach to seek the optimum conditions using Monte Carlo Simulation and specially developed numerical algorithms. The output of the program yields the operating conditions for each individual bit run so that the overall cost are minimized for the entire well phase drilled.

The method does not depend on a particular drilling model and has been tested with several models such as Bourgoyne&Young's, Warren's and others. The paper shows results of using the first two models mentioned due to their greater acceptance within the very small portion of the drilling industry that uses drilling models at all.

The results show an average cost per meter savings of over 10% in most cases and can be as high as 30% depending on the length to be drilled and the number of bits required.