bluuebunny/crossref_metadata_2025 huggingface dataset:
A One-Dimensional Formation Damage Simulator for Damage Due to Fines Migration
Authors: Vitthal S. , Sharma M. M. , Sepehrnoori K.
Published: December 2007

One of the major causes of formation damage is the movement and trapping of fine particles in pores. These fines may be generated in-situ by the interaction of injected fluids with the formation or they may be injected along with the fluids.

A model is presented that simulates the permeability impairment caused by fines migration or injection in a radial geometry. The physical basis for the equations are the same as for a linear model that has been presented earlier 1,2. The equations are quite general and can be used to model the permeability reduction for any given pore or particle size distribution.

The fines migration phenomenon is a moving boundary type problem. The position of the boundary is determined by assuming that it propagates as an ideal sharp front. The set of coupled, non-linear partial differential equations for the model are solved by an implicit finite-differencing technique.

The validity of the simulator is tested against analytical equations that have been developed for some special cases. The agreement between the simulator and the analytical solutions is found to be excellent. The simulator is also used to investigate the importance of various parameters. For example it is found that the pore and particle size distributions, as well as their concentrations have a significant effect on the permeability reduction. Other factors of importance are the rate of release of attached particles and the geometry of the pores. Methods of estimating these parameters are suggested. The use of the simulator to calculate the extent and depth of damage of damage, when fluids are injected into the formation, is demonstrated. It is expected that the simulator will prove useful in the design of such operations.
Key Factors for Enhanced Results of Matrix Stimulation Treatments
Authors: Paccaloni G. , Tambini M. , Galoppini M.
Published: December 2007

Most of the failures of matrix stimulation treatments can be imputed to incorrect field procedures.

To improve the success ratio of the jobs, the tailoring of field stimulation procedures must be strictly linked with the clear identification of the target and with the optimization of the design. Objectives are set to meet different well situations, and require specific design and field procedures.

Maximizing the injection pressure andrate during matrix stimulations has proven to be a very successful technique, particularly effective over extensive pay zones.
Geothermal Well Damage in the Paris Basin: A Review of Existing and Suggested Workover Inhibition Procedures
Authors: Ungemach P. , Turon R.
Published: December 2007

The central part of the Paris Basin of France is one of the largest hot water resources developed to date for district heating purposes. Exploitation addresses reservoirs hosted chiefly in consolidated carbonate rocks and, occasionally, in deeper, clastic sandstone formations. Depths and temperatures range from 1,600 to 2,000 m and 50 to 85°C respectively.

For obvious environmental and pressure maintenance reasons, the production technology is based on the so-called doublet concept. It associates a production well, a heat exchanger transferring the geothermal heat to a distribution network and an injection well conveying the heat depleted brine into the source reservoir.

Among the fifty four such schemes presently operating in the Paris area, one third are undergoing severe exploitation problems. Those consist of well damage which, in most instances, has affected first the injection well, then the producing well. This damage originates from a thermochemically sensitive formation fluid, a hot, slightly acid brine with a fairly low gas liquid ratio. It results in casing corrosion and scaling by heavy metal, mainly iron, sulphide deposits. Yet the origin of this scale, either corrosion generated, bacterial or native, is not clear.

Most workover programmes, based on conventional cable and drill stem technologies, have succeeded in restoring initial well injectivities and productivities by combining casing cleaning/scraping and open hole jetting. However their efficiencies, in terms of durability, are limited to hardly one year.

Chemical inhibition has been attempted on a few sites with varying success. It was based on injection at shallow depths of corrosion and scale inhibitors and bactericides.

Alternative methods are contemplated. They consist of (a) a versatile, cost effective, workover technique using a high pressure large diameter flexible coiled tubing, and (b) of continuous injection down hole of crystal growth inhibiting agents.

Existing restoration and inhibition treatments are reviewed and selected examples presented. Candidate procedures are discussed in the light of damage monitoring and identification of source mechanisms.
Gas Injection Performance Of The Pembina "E" Lease
Authors: Kloepfer C.V. , Tracy G.W. , Last G.J.
Published: December 2007

PUBLICATION RIGHTS RESERVED

This paper is to be presented at the 36th Annual Fall Meeting of the Society of Petroleum Engineers of AIME in Dallas October 8–11, 1961, and is considered the property of the Society of Petroleum Engineers. Permission to publish is hereby restricted to an abstract of not more than 300 words, with no illustrations, unless the paper is specifically released to the press by the Editor of JOURNAL OF PETROLEUM TECHNOLOGY or the Executive Secretary. Such abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in JOURNAL OF PETROLEUM TECHNOLOGY or SOCIETY OF PETROLEUM ENGINEERS JOURNAL is granted on request, providing proper credit is given that publication and the original presentation of the paper.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and considered for publication in one of the two SPE magazines with the paper.

A review of the performance of the Pan American-Hudson's Bay Pembina E Lease, Cardium Reservoir Pembina Field, has been made. Early in the history of this lease it was thought that primary recovery would be low. Waterflooding was considered uneconomical due to the low well injectivity and productivity. However, gas injection using an inverted nine-spot pattern has been shown to be economical. Gas injection facilities were paid out in eight months.

Rapid rises in gas-oil ratio were experienced shortly after gas injection was started. This was found to be a direct result of local depletion around the individual producing wells and not gas channeling. When the oil producing rates were stabilized, the gas-oil ratio began to decline and is still declining.

Calculated recovery estimates indicate that gas injection may increase the recovery of this lease by over 3,000,000 barrels, representing a 48% increase over ultimate primary recovery.

Introduction

The Pan American-Hudson's Bay Pembina E Lease comprises approximately 5,760 acres and is representative of the large portion of the Pembina Cardium Field characterized by a low producing capacity sand development. The E Lease is located in Township 47 and 48, Ranges 9 and 10, W5M in the Province of Alberta. (Figure 1) Under primary depletion the wells on this lease exhibited a gas-oil ratio performance abnormal to most oil reservoirs.
Obtaining Native-State Cores with a Specially Designed Water-Free Coring Fluid
Authors: Hemphill A. T. , Mayes T. M.
Published: December 2007

With the development of a new water-free oil-base coring fluid, extraction of cores in their native or unaltered state is possible. Improvements in laboratory measurements of formation rock properties can now be obtained. In addition to its application as a coring fluid, this system can be used as a drilling fluid.
Advances in Fracturing Techniques in Carbonate Reservoirs in the Howard Glasscock Field in West Texas
Authors: Hoover R. S. , Adams R. L.
Published: December 2007

Significantly increased volumes of proppants have been placed in carbonate reservoirs such as the San Andres formation in the Howard Glasscock field in Howard County, Texas. The treatments that have been performed were accomplished using significantly smaller volumes of liquid. The treatment placement success can be attributed to the incorporation of recent advances in wireline inputs, perforating techniques, and computer design capabilities using accurate reservoir data. New blending equipment capable of computer interaction has also contributed to the ability to accurately schedule and place the higher proppant concentrations.

The use of the previously mentioned components have resulted in controlled fracture heights while taking advantage of in-situ stress barriers. The greater created fracture conductivity will allow for increased production of fluids once this waterflood has been completely implemented.
Cryogenic Nitrogen or Carbon Dioxide Rejection
Authors: Philcox J. E. , Grader R. J. , Gilchrist R. E.
Published: December 2007

The rapid growth of Carbon Dioxide (CO2) and/or Nitrogen (N2) Enhanced Oil Recovery (EOR) projects has resulted in the need for efficient low cost rejection technology. This is particularly true if the Nitrogen or Carbon Dioxide is produced with a natural gas that has an existing market. Basic rejection cycles are described and compared. Key process and mechanical design considerations, especially those unique to Nitrogen and Carbon Dioxide, are emphasized.

The Carbon Dioxide or Nitrogen content in the produced gas increases with time over the life of a project, so the rejection equipment must perform satisfactorily over a broad range of feed compositions. Recycling the rejected Carbon Dioxide or Nitrogen is a cheaper source of injection gas than its original source. A rejection unit can be designed as an add-on unit to existing natural gas processing facilities in which much of the stabilization, pre-treatment, and liquid recovery already exists.

A sample application for nitrogen rejection is presented including process performance and simple economics for a "typical" case.
Carbonate Production Decline Rates Are Reduced Through Improvements in Gelled Acid Technology
Authors: Johnson D. E. , Fox K. B. , Burns L. D. , O'Mara E. M.
Published: December 2007

Over 300 matrix and fracture acidizing treatments, utilizing a thermally stable acid gelling agent, were performed in carbonate formations, worldwide. The initial results of several treatments were presented earlier (Ref. 1). Since then, trends toward sustained increases in production have been documented and are presented. Reductions in production decline rates have resulted in improved recovery of reserves.

Improved live acid penetration results from the effects of stable viscosity, retarded reaction rate and proper treatment design. In addition, the gelling agent must be non-damaging, requiring tolerance to calcium and magnesium ions in the spent acid during cleanup. A gelling agent is described that provides the features of thermal stability and solubility in the live and spent acid.
A Review of the Methods of Estimating Stabilized Absolute Open-Flow Potential of Gas Wells
Authors: Poe B. D. , Jennings J. W.
Published: December 2007

This paper presents a review of the practical backpressure test analyses available for estimation of the stabilized absolute open flow (AOF) potential of natural gas wells. Linear regression analysis techniques have been used to correlate the field-recorded deliverability data and statistical influence tests have been used to identify possible outliers in the test data.

The types of backpressure tests considered in this study are the conventional flow-after-flow (four point), single point, regular and modified isochronal backpressure tests, and the multiple modified isochronal test. The deliverability analyses considered in this paper are the Rawlins-Schellhardt pressure-squared, and the Houpeurt (quadratic) real gas pseudopressure and pressure-squared analyses. Modified versions of these analyses are used in the analysis of multiple modified isochronal tests.

The analysis techniques developed for multiple modified isochronal tests were reviewed and found to permit a rapid and adequate means of estimating the stabilized AOF potentials of slow-in-stabilizing wells in homogeneous reservoirs, using only the semilog transient isochronal deliverability data. Theoretical considerations are also introduced which may provide a means of estimating stabilized AOF potentials of gas wells completed in naturally fractured reservoirs. A discussion is also included on the estimation of stabilized AOF potentials of wells completed in homogeneous reservoirs, which have been vertically fractured to increase their productivity.
A Tool To Eliminate Common Sucker Rod Pump Problems
Authors: Spears H. L.
Published: December 2007

This paper describes a tool which employs simple mechanical technology to solve common sucker rod problems of gas locking and sticking without undesirable impact and wear on the pumping equipment.
History Match of the Maljamar CO2 Pilot Performance
Authors: Moore J. S. , Clark G. C.
Published: December 2007

A miscible CO2 flood pilot conducted in the Maljamar field, New Mexico, was formally completed January 1, 1986. This paper presents the results and developments of numerically history matching the 6th (Grayburg) and 9th Massive (San Andres) zone CO2 pilots. The purpose of this pilot was to gain information that would reduce the operational and economic uncertainties of a full-scale project. Special features of the 5-acre (20,200 m2) inverted 5-spot pilot include (a) dual (separate) completions in the Grayburg and San Andres zones and (b) two fiberglass-cased logging observation wells for in situ monitoring of oil, brine, and carbon dioxide movement. The logging observation wells illustrated that the miscible CO2 flood process can significantly reduce oil saturations in the 6th and 9th Massive zones at Maljamar. The high CO2 retention, high minimum water saturation, and low CO2 injectivity exhibited in the pilot can be accounted for through relative permeability hysteresis and a possible change in rock wettability. By incorporating these mechanisms into the simulator, a reasonable match of oil and CO2 production, fluid injectivity, and observation well saturation profiles demonstrated the validity of the approach. The calibrated performance parameters were used as a basis for making fieldwide performance predictions for the Maljamar field.
Evaluation of Commercial Crosslinked Polyacrylamide Gel Systems for Injection Profile Modification
Authors: Purkaple J. D. , Summers L. E.
Published: December 2007

This paper describes a unified testing program to identify the best polymer gel systems for a particular field application. Beaker tests are used to rapidly screen gel systems. Coreflood tests are then employed for the final system selection.

Results are presented from a full-scale laboratory evaluation of 15 commercially available polyacrylamide polymers with a Cr(III)-redox crosslinker for profile modification in a thick, multizone reservoir. Beaker tests showed that low levels of polymer hydrolysis were required to produce consistent gels at reservoir conditions. In addition, the pH of the gel solution in the buffered field brine had a large effect on the gel properties. Allied Cglloids Alcoflood ®935L and American Cyanamid Cyanagel ®150 were selected for further evaluation in coreflood tests. Either polymer gel maintained a permeability reduction of at least 97 percent after 50 days of static aging at reservoir conditions. The stability of an Alcoflood 935L gel was evaluated during continuous injection and with exposure to near wellbore pressure gradients.
Miscible Flood Performance Predictions for a Full-Field Project Using Multiple Prototypes To Represent Individual Wells
Authors: Chernik P. S. , Symonds R. W. , Todd M. R.
Published: December 2007

A prototype simulation approach, with appropriate scaling factors, has been devised so that prototype simulations can be scaled to yield the performance of individual sub-segments (zones) within wells. The predicted performance of the sub-segments are summed to yield pattern element performance and these in turn are summed to yield a performance forecast for the area of interest. The prototype approach has been used to generate waterflood and miscible flood performance predictions for a portion of the Virginia Hills Beaverhill Lake Unit.
The Effects of Small-Scale Heterogeneities on the Effective Dispersivity of Porous Medium
Authors: Kelkar B. G. , Gupta S. P.
Published: December 2007

Dispersivity affects the displacement and sweep efficiencies and the required slug size of a displacing fluid. Unfortunately, the dispersivity values estimated from field tests are a few orders of magnitude greater than the values obtained in laboratory tests. This investigation studies the effect of small scale (or core scale) heterogeneities on the effective dispersivity value in a typical gridblock size used in a reservoir simulator. The study is restricted to contact miscible displacements with unit mobility ratio. A finite element simulator is used to investigate these effects. Physical dispersion is explicitly included in the simulator.

Results show that the effective dispersivity is affected by the degree of heterogeneity, the average length of heterogeneity, the length of the system, and the manner in which the permeability values are spatially distributed. The effect of heterogeneity becomes significant if the coefficient of variance is greater than 0.4. The effect of dimensionless scale length (ratio of average length of heterogeneity to length of the system) on effective dispersivity is insignificant for dimensionless scale values less than .01; above that value dispersivity increases with an increase in the scale length. The effective dispersivity increases almost linearly with an increase in the length of the system for constant dimensionless scale length. This provides an explanation for the similar trend reported for field dispersivity data. A simple correlation is proposed to calculate the effective dispersivity of the porous medium. The effect of the way in which given permeability values are distributed across the medium on the dispersivity cannot be correlated with the parameters investigated, probably indicating that the effective dispersivity is a unique function of the manner in which permeability values are distributed. This effect was not noted previously in the literature; however, it does not affect the general trends.
Foam Flooding of Cores Under North Sea Reservoir Conditions
Authors: McPhee C. A. , Tehrani A. D. H. , Jolly R. P. S.
Published: December 2007

Laboratory corefloods were run to explore the feasibility of foam to provide mobility and injection profile control in a stratified, heterogeneous North Sea reservoir. The objectives were to identify suitable surfactants, from over 100 commercial surfactants initially screened, which were capable of producing stable foam at North Sea reservoir conditions and, to quantify the influence of several reservoir and injection parameters upon foaming performance.

The experimental apparatus essential for the laboratory simulation of foam generation and injection into porous media at reservoir conditions is described.

The test results showed that, compared with brine injection alone, three surfactants were each capable of substantially increasing core pressure gradients in synthetic porous media, when injected with nitrogen gas at conditions of 4300 psig (29.6 MPa) and 230°F (110°C). Effective, resilient foams can also be generated within natural sandstone cores at injection velocities of 10 ft/d (3.05 m/d).

Based on the surfactants evaluated in this study, the dramatic reduction in foam pressure drop (by up to 80 times) in the presence of the North Sea crude used, effectively precludes the use of foam to restrict water or gas channelling at North Sea pressure and temperature.
A New Method for Testing of Gas-Blocking Foams
Authors: Hanssen J. E.
Published: December 2007

A study of foams as gas-blocking agents in model porous media is reported. Foams are generated by displacing surfactant solution with gas, and tested by meas·uring gas permeability as a function of step-wise increasing differential pressure. The method gives a direct, in-situ measurement of foam gas-blocking ability which is sensitive to differences among surfactants tested. Contrary to some previous reports, no correlation is found between surfactant performance in gas-blockage, tests and in bulk foam tests. It is suggested to employ the gas-blockage method for screening purposes instead of bulk tests in studies directed at obtaining maximum gas blockage of porous media.
Integrated Geological/Engineering Model for Barrier Island Deposits in Bell Creek Field, Montana
Authors: Honarpour M. M. , Szpakiewicz M. J. , Schatzinger R. A. , Tomutsa L. , Carroll H. B. , Tillman R. W.
Published: December 2007

Geological heterogeneities controlling fluid production from the Lower Cretaceous Muddy formation in the Tertiary Incentive Project (TIP) and adjacent area in Unit ‘A’ of Bell Creek field Montana were investigated. Production and injection performance and production test data, as well as core, log, and structural data, were integrated to provide an improved geological/engineering model. The model was used to study the influence of the various scales and nature of geological heterogeneities on fluid flow and residual oil saturation distribution in the reservoir.

Information from primary production; initial production rate potential distribution; cumulative primary, secondary, and tertiary production; pressure transient test data; water injection front tracking; electrical resistivity changes due to depletion of residual oil; injectivity histories of injection wells; and areal simulations was integrated to identify fluid flow patterns and residual oil saturation distribution.

Production performance and oil saturation distribution in Unit ‘A’ of Bell Creek field were affected by critical multigenetic heterogeneities, such as stratigraphy and dimensions of facies, valley incisions into the best productive barrier island sediments, high-permeability "channels," reduction in net pay due to diagenetic clay content, faulting and structural dip. These heterogeneities result in large production/residual oil saturation contrasts over small distances. Results of the study showed that the most productive part of Unit ‘A’ is associated with regions of well-developed high-energy barrier island facies (upper shoreface and foreshore); low amounts of diagenetic clay cement; and absence of structural discontinuities. The influence of nature and the scale of geological heterogeneities varied at different stages of oil recovery.

The understanding of reservoir performance in the barrier island system was improved by integrated multidisciplinary analyses of standard data and comprehensive approach to geological and engineering interpretation.
Calculation of Multiphase Equilibrium for Water-Hydrocarbon Systems at High Temperature
Authors: Nutakki R. , Firoozabadi A. , Wong T. W. , Aziz K.
Published: December 2007

Multiphase equilibrium calculations for binary, ternary, and quaternary hydrocarbon-water systems at high temperature were performed using the Schmidt-Wenzel equation of state. The solubility of water in the hydrocarbon-rich liquid phase and vapor phases is modelled using a constant binary interaction parameter between water and hydrocarbon, while the solubility of hydrocarbons in the aqueous phase is calculated using a temperature dependent binary interaction parameter. Two and three phase equilibrium calculations were performed using the method of successive substitution. A stability analysis using the tangent plane criterion was used to determine the correct number of phases present.

At high temperature the solubility of water in hydrocarbon liquids can be quite large. Using the procedure outlined above the solubility of water in the hydrocarbon-rich liquid phase was calculated accurately both for mixtures of water and pure hydrocarbon components, and for mixtures of water and petroleum fractions. The binary interaction parameters used in the hydrocarbon-rich liquid phase and the vapor phase were found to be dependent on the type of hydrocarbon. The interaction parameters for components in the same homologous group such as alkanes, aromatics, and alkenes were found to be almost the same.

The solubility of hydrocarbons in the aqueous phase was calculated reasonably accurately using temperature dependent interaction coefficients in the aqueous phase. Above 200 °F, the binary interaction parameters in the aqueous phase were linear functions of temperature. Binary interaction parameters from two phase binary data were found to be quite adequate to calculate three phase multicomponent equilibrium.
Correcting Oil/Water Relative Permeability Data for Capillary End Effect in Displacement Experiments
Authors: Qadeer S. , Dehghani K. , Ogbe D. O. , Ostermann R. D.
Published: December 2007

Capillary effects in low flow rate displacement experiments cause error in relative permeability values calculated by JBN or Jones and Roszelle methods. The results from a series of displacement and capillary pressure experiments were used along with a history matching package to quantify the changes in relative permeabilities with rate. The experiments were conducted with different rates on short and long cores. The history matching procedure was developed using a one-dimensional, two phase finite difference simulator, and the Levenberg-Marquardt optimization algorithm.

Exponential form for relative permeability functions were used and the change of function parameters with rate was investigated. The results show that for the case of drainage the relative permeability parameters (i.e., end-point relative permeability and saturation exponent) have functional relationships with rate. The saturation exponent in non-wetting phase and the end-point nonwetting relative permeability increase with rate. However, the end-point relative permeability to wetting phase did not show any significant change but the saturation exponent in the wetting phase decreased with increase in rate. Regression equations of these changes were developed. In the case of imbibition, these parameters did not indicate any meaningful trend with rate.
An Overview of Formation Damage and Well Productivity in Oilfield Operations: An Update
Authors: Krueger R. F.
Published: December 2007

Almost every field operation is a potential source of damage to well productivity. This paper provides a broad overview of the nature of formation damage problems, how they occur during various oilfield operations, and their effects on well productivity.

Diagnosis of numerous formation damage problems has led to the conclusion that formation damage is usually associated with either the movement and bridging of fine solids or chemical reactions and thermodynamic considerations. The fine solids may be introduced from well bore fluids or generated in situ by the interaction of invading fluids with rock minerals or formation fluids.

Control of formation damage requires proper design of treating fluids for chemical compatibility and strict quality control of fluid physical and chemical properties during treatment. The use of treating fluid filtration, clean work strings (pipe), and inhibited fluids has been shown to be important in the control of formation damage during well treatment.
Mechanisms of Capillary Displacement of Residual Oil by Gravity-Assisted Inert Gas Injection
Authors: Kantzas A. , Chatzis I. , Dullien F. A. L.
Published: December 2007

Very high oil recoveries are achieved when an inert gas displaces continuous oil or residual oil downwards in water wet columns of glass beads and in sandstone cores, provided that a semipermeable membrane is used at the production end to prevent gas breakthrough. In this paper, pore level mechanisms that control this displacement process are elucidated, as revealed by experiments in 2-dimensional pore network micromodels and unconsolidated columns of glass beads. Visualizations of the displacement mechanisms are presented and their effect on oil production is discussed. By applying principles of capillarity and by using well defined pore geometries, equations have been developed for predicting both water and oil distributions at the pore level.
Installation of Retrievable Liners
Authors: Manley D. D.
Published: December 2007

In today's oil and gas economic environment, oil and gas wellbores must remain competent for long-term production and injection use. Secondary recovery, waterflooding, and tertiary recovery methods of polymer and carbon dioxide injection have given new life to old wells, requiring even

longer use of existing wellbores. Wellbore integrity tests required by state and federal regulations, are designed to protect fresh water zones, prevent hydrocarbon migration into unwanted zones of porosity and insure that wellbores are not in communication with the strata behind the pipe. These integrity tests and the longer more demanding use of wellbores have contributed to oil and gas operators discovering that lengthy sections of the original casing string have disintegrated. Contributing factors of casing failures are external corrosion, electrolysis, and internal metal loss, due to hydrogen sulfide and carbon dioxide. "Retrievable" liner installations provide a method of ameliorating the casing problems, and restoring the old wellbore to service. Through the use of a gelatinous, thixotropic oil-base packer grease, instead of cement, placed in the annular area between the newly installed liner and the original casing string the liner become retrievable. When initially mixed the oil-base packer fluid is liquescent enough to be pumped into the annulus. In a quiescent state it develops the consistency of a stiff grease. Upon agitation, the packer fluid will alter to a consistency capable of being pumped, thus allowing the liner to be recovered.

The retrievable liner provides an alternative to squeeze cementing where the deteriorated casing length is too long to provide for adequate cement fill. The liner offers a method to protect the active production or injection zone from foreign fluid invasion and when needed, allows the installation of special alloy liner equipment to protect against hydrogen sulfide and carbon dioxide environments.
The Water Quality Control Station: A New Monitoring Tool for Injection Water
Authors: Meyer D. R.
Published: December 2007

The success or failure of secondary and tertiary recovery operations can depend in large measure on maintaining the quality of the water chosen to carry the EOR chemicals and to displace and move the oil through the formation matrix toward the producing wells.

Some commonly accepted indicators of poor water quality include the presence of corrosion and its by-products, carbonate and sulfate scale formation and deposition, oxygen and elevated dissolved acid gas levels, high bacterial populations, heavy suspended solids load and oil carryover.

At present, engineers and operators typically rely on periodic, yet relatively infrequent, monitoring of the injection water in order to obtain the data necessary for good water management. Periodic monitoring however may allow occasional but potentially damaging system upsets to occur without detection.

The relative uncertainty of intermittent sampling can be greatly reduced by combining the benefits of continuous in-line filtration with controlled flow rates, accumulated volume, and monitoring of scale and corrosion tendencies. Changes in water quality can therefore be quickly recognized and appropriate, timely measures initiated.

This paper discusses the installation of a Water Quality Control Station, the individual components, and the contribution of each to the definition of water quality problems. A key field case history is presented to show how the concept is applied.
Horizontal Drilling of Eolian Nugget Sandstone in the Overthrust Belt
Authors: Greener J. M , Sauvageau K. A. , Pasternack I.
Published: December 2007

The horizontal recompletion of the Ryckman Creek Well #21 was the first to be attempted in a Thrust Belt Nugget field. The horizontal completion is significant because of the potential to substantially increase oil reserves over what can be produced with conventional methods. A horizontal wellbore has the ability to penetrate long intervals of an oil zone and expand the well's drainage area. The greater open productive interval permits lower drawdown pressures, alleviating the stratigraphic gas/water coning tendencies that have plagued many Nugget fields.

To recomplete the Ryckman Creek #21 as a horizontal wellbore, a directional program was designed to incorporate industry proven tools and techniques. A section was milled in the 7 in (17.7 cm) production casing at a predetermined elevation above the desired horizontal target zone. Medium radius of curvature (20 degrees/100 ft [30.5 m]) tools were utilized to drill the curved portion of the wellbore. A total of 534 ft (162.8 m) of lateral hole was drilled with a steerable bottomhole assembly. The amount of open productive interval was a five-fold increase over the vertical completion originally performed in the Ryckman Creek #21 well.
Permeability Damage to Natural Fractures Caused by Fracturing Fluid Polymers
Authors: Gall B. L. , Sattler A. R. , Maloney D. R. , Raible C. J.
Published: December 2007

Formation damage studies using artifically fractured, low-permeability sandstone cores indicate that viscosified fracturing fluids can severely restrict gas flow through these types of narrow fractures. These studies were performed in support of the Department of Energy's Multiwell Experiment (MWX). The MWX program was a coordinated research effort to study methods to evaluate and enhance gas production from low-permeability lenticular reservoirs of the Western United States.

Extensive geological and production evaluations at the MWX site indicate that the presence of a natural fracture system is largely responsible for unstimulated gas production. The laboratory formation damage studies were designed to examine changes in cracked core permeability to gas caused by fracturing fluid residues introduced into such narrow fractures during fluid leakoff.

Polysaccharide polymers caused significant reduction (up to 95%) to gas flow through cracked cores. Polymer fracturing fluid gels used in this study included hydroxypropyl guar, hydroxyethyl cellulose, and xanthan gum. In contrast, polyacrylamide gels caused little or no reduction in gas flow through cracked cores after liquid cleanup. Other components of fracturing fluids (surfactants, breakers, etc.) caused less damage to gas flows.

The results of fluid leakoff tests indicated that polysaccharide polymers caused a filter cake buildup at or near the crack entrance while polyacrylamide polymers did not cause a filtercake buildup within the time period of the tests. For xanthan gum gels filtercake buildup was reduced for gels containing polymer breakers. For gels containing polymer breakers, 100 mesh sand was an effective fluid-loss control agent for narrow fractures.

Other factors affecting gas flow through cracked cores were investigated, including the effects of net confining stress and non-Darcy flow parameters.

Results are related to some of the problems observed during the stimulation program conducted for the MWX.
Use of Wet Gas Flow for Long-Term Fracture Conductivity Measurements in the Presence of Gel Filter Cakes
Authors: McDaniel B. W.
Published: December 2007

For an operator to predict well production after a fracturing treatment it is necessary to estimate the conductivity of the propped fracture. The validity of these predictions rests on the accuracy of the fracture conductivity estimates. This emphasizes the need to perform laboratory conductivity measurements which effectively simulate reservoir conditions.

Major advances have recently been made in laboratory attempts to measure realistic fracture conductivity values for proppants at reservoir conditions. However, even the most realistic laboratory simulations have used 2% KC1 brines as the flowing medium instead of a gas or hydrocarbon fluid. In an attempt to better simulate fracture conditions in a gas well, the work presented here includes these nine important test parameters: (1) reservoir temperature, (2) extended test time, (3) core wafers, (4) gel residue in the proppant pack, (5) gel filter cakes from dynamic fluid loss tests, (6) frac fluid clean-up period, (7) wet gas as flowing medium, (8) varying closure stresses, (9) non-darcy flow effects.

Using these procedures, with a linear flow conductivity cell, tests have been performed with three different gel systems. These results will be compared to recent work using brine water as the flowing medium, and to other works using gas flow for proppant conductivity measurements.
PUDDLE-PACK Recompletion Propped Fracturing Techniques to Improve Productivity of Multipay Producing Wells
Authors: Darr C. D. K. , Carlton J. C.
Published: December 2007

To increase productivity of a three zone, shot, open hole completion, a "PUDDLE-PACK" has been successfully completed and all three zones individually stimulated. MCA Unit #103, located in Southeast New Mexico, experienced a 2.75 fold production increase after "PUDDLE-PACK" completing and hydraulically fracturing two San Andres intervals and acidizing one Grayburg interval.

The first attempt to hydraulically fracture the lower San Andres zone failed. As a result of the failure to hydraulically fracture the bottom San Andres "PUDDLE-PACK" completed interval, mechanical property and perforation tests were performed on the resin fill material used in the "PUDDLE-PACK" completion process. After analyzing the test data, corrective remedial operations were designed. These remedial adjustments allowed the two San Andres "PUDDLE-PACK" completed intervals to be successfully hydraulically fractured.

This paper describes in detail, the need for selective stimulation of MCA Unit #103, one initial remedial operation, the resin coated gravel fill material mechanical properties testing results, the resin coated gravel fill test perforating results, the remedial operation changes required to hydraulically fracture a "PUDDLE-PACK" completed well, and a complete evaluation of well performance.
Well Test Analysis of Pumping Wells in Multiphase Naturally Fractured Reservoirs
Authors: Aguilera R. , Houston M. , Podio A. L. , Song S. J.
Published: December 2007

Bottom hole buildup pressures on three Wyoming pumping wells have been determined based on liquid level in the annulus as determined from a computerized acoustic device.

These buildup data correspond to a naturally fractured reservoir which produces oil, gas and water. Basic formulations and three case histories are presented:

The case of a well with after flow effects where the buildup data are properly matched using type curves for dual-porosity systems with restricted (pseudo steady state) interporosity flow and the pressure derivative. The case of a stimulated well in a naturally fractured reservoir. In this situation a conventional log-log crossplot of delta p vs. time results in two parallel straight lines with slopes equal to 0.5. Separation between the two lines allows calculation of the storativity ratio, omega. The case of a well in a layered naturally fractured reservoir with variable afterflow effects.

In this case a log-log plot of delta p vs. time shows two parallel straight lines with slopes equal to 1.0. A good match of the data is obtained with a dual-porosity model and the pressure derivative starting at the second 1.0 slope straight line.

Acquisition of the raw data, conversion into bottom hole buildup pressures, and analysis utilizing dualporosity models are presented in detail. It is concluded that pumping wells in naturally fractured reservoirs can be properly evaluated when all phases flowing are taken into account.

The same procedure and formulations presented in this work can be utilized for analysis of conventional singleporosity reservoirs by making Warren and Root's omega equal to 1.0.
Application of Equivalent Drawdown Time in Well Testing
Authors: Swift S. C.
Published: December 2007

The concept of equivalent drawdown time was described by Ram Agarwal in 1980. In reality it has been in common use in well test analysis since at least 1950. However, in 1988, application of the concept is still not widely understood. The purpose of the present paper is to encourage its application by clarifying its role in well test analysis.
Petroleum Education in the People’s Republic of China
Authors: Von Gonten W. D. , Calhoun J. C. , Hongfan Chen
Published: December 2007

Petroleum education in China is, like petroleum production itself, a development of relatively recent years. In 1949, when the annual crude oil output was 120,000 tons and workers in petroleum numbered 8,000, no petroleum schools or colleges existed. In 1987, when the production reached 134 million tons with a work force of 1.2 million, there were seven petroleum institutions of higher learning. This paper will outline the petroleum education system as it exists today and present some observations on the issues that it faces.

The first formal petroleum education program was a petroleum engineering department in Tsing Hua University. In 1953, this department became the nucleus of the The Peking Petroleum Institute, the loyalties to which are still felt today in the entire petroleum education system of China. The Peking Petroleum Institute evolved, in 1969, into the East China Petroleum Institute.

There are now seven higher educational institutions devoted to petroleum education in China. Of these, Fushun Petroleum Institute is under the administration of the China Petrochemical Corporation and Xinjiang Petroleum Institute is under the administration of the Xinjiang Uygur Autonomous Region. The other five institutes are under the administration of the Ministry of Petroleum Industry (M0PI). These are East China Petroleum Institute, which is the oldest, largest and most comprehensive, Daqing Petroleum Institute, Jianhang Petroleum Institute, Southwest Petroleum Institute, and Xian Petroleum Institute, which is the newest and smallest. M0PI has given top priority to assessing the quality and future of its petroleum education. In addition to its own continuing internal analysis, the M0PI, in 1986, invited a team of petroleum educators from Texas A&M University to review the petroleum education program and to make recommendations for its future. This paper is based on some of the observations resulting from that review.
Design Aspects in Reflection Seismology Aiming at Rock Properties Detection
Authors: Bilgeri D. , Carlini A.
Published: December 2007

The geological complexity of many hydrocarbon traps and the related seismic anomalies often give rise to serious difficulties in inferring geological characteristics from seismic signals.

Optimum seismic processing sequence can be carefully designed only after an accurate analysis of the available seismic and geological data in order to single out the geophysical problems to be solved in the particular exploration site.

Stratigraphic processing architecture requires the use of the residual propagating wavelet in order to transform the reflectivity section into a profile of calibrated seismic logs which represent a quantitative datum bearing structural and stratigraphic information.

Seismic logs obtained from surface seismics integrated with borehole data and correlated to studies of reservoir-rocks allow to detect the reservoir internal structure in terms of geometries and lateral variations of petrophysical properties.

Combining seismic-petrophysical profiles with the depositional model enables to move within possible solution ranges, through sensitivity analyses and confidence limits of the observational data, towards the unique and most proved solution of the sedimentary features of the investigated layers.

This methodology was tested with a pilot project in an oil bearing pre-Miocene limestone of a field in Central Italy. Thickness and porosity variations were determined from absolute seismic logs obtained from land seismic data recorded during different years (77–84) and processed optimizing: signal amplitude and phase, field and residual statics, wave velocity propagation.

The resulting distribution of reservoir heterogeneity will technically and economically affect the techniques related to enhanced oil recovery.
Production Forecasting Methods for Horizontal Wells
Authors: Joshi S. D.
Published: December 2007

This paper summarizes production forecasting methods for horizontal wells. The forecasting methods are based on analytical solutions and correlations of numerical model results. Methods are suggested for single phase flow, solution gas drive, naturally fractured, and bottom water drive reservoirs. These forecasting methods could be used for an initial evaluation of horizontal well drilling prospects.

A horizontal well can be looked upon as a controlled infinite-conductivity vertical fracture of limited height. Therefore, this paper compares horizontal well productivity with finite and infinite-conductivity, and uniform-flux fractures. A choice between horizontal wells and stimulated vertical wells should be determined by considering local fracturing experience and local costs for stimulation treatments and horizontal drilling.
Recovery of Viscous Oil Under High Pressure by CO2 Displacement: A Laboratory Study
Authors: Chung F. T. H. , Jones R. A. , Burchfield T. E.
Published: December 2007

Laboratory coreflooding experiments were performed to investigate the technical feasibility of the use of the CO2 flooding process under immiscible conditions for the recovery of viscous oil. A stock-tank oil of 22° API gravity was recombined with solution gas at a gas-oil ratio (GOR) of 48 scf/bbl. The CO2 flooding tests were conducted in a consolidated Berea sandstone core under simulated reservoir conditions. The viscosity of the recombined oil at reservoir temperature (152° F) and pressure (2,500 psig) was 50 cp. Experimental results show that the oil viscosity was reduced to 8 cp, and the oil volume was swelled to 1.2 times the original volume after saturation with CO2 at the testing condition.

Oil recovery from a 2-in.-diameter and 2-ft-long core by CO2 flooding for the testing oil was unusually high even under Immiscible conditions. The ultimate oil recovery from a secondary CO2 flood is as much as 60 % of the original oil in place (OOIP), which is higher than the average oil recovery from a secondary waterflood, 44 % OOIP. After waterflood, a continuous injection of 1.5 PV of CO2 recovered an additional 33 % OOIP. The CO2 utilization factor was 11.7 Mscf/bbl of additional oil recovered. The CO2-alternate-brine injection method significantly delayed the breakthrough of gas and provided a slightly higher oil recovery and more efficient CO2 utilization than the continuous CO2 injection method. Overall, the ultimate residual-oil-saturation (Sor) was reduced to 18% PV by all of the above CO2 injection methods.