bluuebunny/crossref_metadata_2025 huggingface dataset:
Drilling Safely at Well Design Limits: A Critical Well Design Case History
Authors: Quitzau Robert , Muchtar J. B.
Published: December 2007

Risks of blowouts while drilling deep, high pressured wells can be managed through strenuous well planning and operational contingencies. A new risk management parameter, killable kh, along with conventional drilling parameters were used on the Madura CD-1 well to select casing points, develop operational contingencies and safely drill to high pressured objectives offshore Indonesia.
Horizontal Injection and Production Wells for EOR or Waterflooding
Authors: Taber J. J. , Seright R. S.
Published: December 2007

This paper describes the potential benefits of using combinations of horizontal injection and production wells for EOR processes or waterflooding.

Our results show that a very favorable configuration occurs when two opposed horizontal wells are drilled from injection and production wells so that the opposed laterals are parallel in the patterns, and extended until the horizontal segments almost meet midway between the like wells. Compared to five-spot patterns with vertical wells, opposed horizontal wells can increase injectivity (injection rate per applied pressure drop) by as much as a factor of ten, depending on well spacing and formation thickness. Areal sweep efficiency can be increased by 25% to 40%. The horizontal-well advantages are greatest for thin formations with wide spacing, and decline significantly for thick formations and/or close spacing. Also, for a given injection pressure, the pressure gradient in the bulk of the reservoir can average several times greater when using opposed horizontal wells than when using vertical wells. This could significantly improve microscopic displacement efficiencies for EOR processes, such as micellar/polymer flooding, that are sensitive to interfacial tensions.

Because of the better sweep efficiencies, faster flooding rates, and/or lower injection pressures that are possible with horizontal wells, all EOR methods should benefit by their use. For example, polymer floods can be improved by the higher injectivity and lower rates of shear at the injection sandface. The advantages of horizontal wells for CO2 flooding include: (a) delayed CO2 breakthrough because of the better sweep efficiency, (b) the potential for maintaining the MMP in more of the reservoir with no increase in the injection pressure, (c) better injectivity at the same pressures, and (d) the opportunity to convert more pumped producers to flowing wells. Thermal EOR was not investigated in this work, but the cited references show that horizontal wells have been successful in several field applications and more projects are being planned.
A Simple Technique to Forecast CO2 Flood Performance
Authors: Shaw E. C.
Published: December 2007

This paper presents a technique which takes a one-dimensional (1D) compositional simulation output and scales the results up to an entire pattern. The scale-up procedure takes into account the pore volume and heterogeneity of the pattern. Several parameters are adjusted to match the production history allocated to the pattern. Once a model has been developed to reproduce the waterflood performance, the initial date and target volume of carbon dioxide (CO2) injection is specified.

This scale-up technique has been successfully applied to forecast the performance of the McElmo Creek Unit CO2 project (SE Utah), in operation since 1985. A history match was obtained for each of the 119 patterns in the project. In the mature CO2 flood patterns, both secondary and tertiary performance was matched. The composite of all the pattern forecasts closely follows the actual production history. The production and injection forecasts will be used to determine future water handling and gas processing requirements, and will assist with planning the timing of further field development.
The Rotating Tubing Hanger System: A Unique New System Designed to Extend the Run Time of Rod Pumped Wells
Authors: Lacy R. D.
Published: December 2007

Beam pump systems are among the most cost efficient artificial lift systems in the industry, assuming a long run time between pulling jobs to repair tubing failures caused by rod wear. The tubing string represents the second largest investment in the well. Tlie longer the period of time the well can be kept on-line and producing between pulling jobs, the more efficient and cost effective is the beam pump system.

This paper will describe in detail the conception, development and implementation of a new system that extends tubing life on rod punped wells. The system Lises a very simple concept; rotate the tubing string to extend the length of time between tubing failures and the resultant pulling jobs. The system is pcwered directly from the walking beam and requires no additional power source; nor does the system use any additional energy.

Case histories will be presented that document the effectiveness of the system in extending tubing life and reducing operating costs on rod pumped wells. Data will be presented which shews the system can be effective in reducing problems caused by paraffin build-up, resulting in extended pumping time and additional savings in operating expenses.
Pressure Transient Digital Data Acquisition and Analysis From Acoustic Echometric Surveys in Pumping Wells
Authors: McCoy J. N. , Podio A. L. , Becker Dieter
Published: December 2007

Increased efficiency in production operations requires that the formation and completion characteristics be well defined and analyzed before committing funds to stimulation and/or workover operations. Such information is generally obtained from analysis of pressure transient data measured with wireline recorders. Until recent times, these measurements have been seldom made in pumping wells, due to the time required to trip the rods and pump out of the tubing in order to run the wireline pressure recorders. This need spurred the development of techniques for calculation of transient bottomhole pressure from surface measurements.

This paper describes the design and application of a fully digital system for automatic calculation of bottomhole pressure from echometric surveys of the annular fluid level. This portable system integrates specially designed high resolution A/D conversion and conditioning with advanced signal processing and digital filtering techniques. This results in very accurate determination of the depth to the fluid level, even in the presence of background noise caused by gaseous liquid columns.

Automatic signal generation and recording is undertaken by the software at predetermined, operator selected frequency so as to maximize the quality of the pressure transient data. Surface pressure and temperature measurements are used in conjunction with gas gravity and gas acoustic velocity to determine the pressure at the gas/liquid interface and the pressure at the sandface.

Graphic displays allow the operator to monitor the progress of the transient test by plotting in real time the current status of the well, the acoustic signals and the calculated pressures. Data that has been acquired at that point can be plotted as standard transient analysis graphs ( Horner, MDH, Log-Log etc.) Data files can be exported to other analysis programs.
Gas Research Institute Hydraulic Fracture Test Site
Authors: Robinson B. M. , Syfan F. E. , Holditch S. A.
Published: December 2007

The Gas Research Institute (GRI) Tight Gas Sands program has conducted hydraulic fracturing research since 1983 to learn how to compute and/or measure the shape and extent of a hydraulic fracture in real time. GRI has conducted field projects in the Travis Peak and Cotton Valley sands in east Texas, the Canyon Sands in west central Texas, and the Frontier sands in southwestern Wyoming. These field projects have lead to substantial progress in the understanding of tight gas reservoirs and hydraulic fracture stimulation processes. In addition, new technology has been developed that has improved fracture modeling and fracture diagnostic methods.

Even with substantial progress over the years, there are still many "questions" concerning the hydraulic fracturing process. One problem is that few data sets are available to test and validate the results generated from 2-D and 3-D fracture propagation models. To provide "Proof-of-Concept" experiments to validate fracture propagation models and to resolve certain questions concerning the fracturing process, GRI has designed a Hydraulic Fracture Test Site (HFTS). The HFTS will be used to conduct experiments and gather data sets that will be valuable to both fracture model developers and scientists involved with fracture diagnostic measurements.

This paper summarizes the goals, research objectives, and planning requirements set forth for the HFTS. Data have been gathered on three tight gas formations that have been identified as candidates for the HFTS laboratory. These formations include the Canyon sandstone in the Val Verde Basin, the Corcoran sandstone in the Piceance Basin, and the Clinton sandstone in the Appalachian Basin.
High-pH-Tolerant Enzyme Breaker for Oilfield Applications
Authors: Gupta D. V. S. , Pakulski M. K. , Prasek Beth , Franklin V. F.
Published: December 2007

The use of high pH fluids, particularly borates, has been very prevalent at low to moderate temperatures in the industry and their use at high temperatures is also increasing. These non-metallic borates have been claimed to be less damaging to formations than metallic crosslinked gels. Breakers are commonly used in these aqueous fluids viscosified with guar, cellulose or their derivatives to degrade these fluids after the placement of proppant. Breakers are necessary to minimize permeability damage to proppant pack or formation face at temperatures where there is little thermal degradation of the polymers. The typical breakers that are used in fracturing fluids are enzyme breakers and oxidizers. Unfortunately, at temperatures below 150°F, persulfates, the typical oxidizing breakers, are not effective unless used in large concentrations or used with catalysts. On the other hand, conventional enzymes are not active in high pH systems (>8.5) typical of borates. It has been shown that enzymes break the gels much more efficiently in low to neutral pH fluids1.

A new enzyme described in this paper is active in fluids in the pH range 5 to 11. The specially engineered enzyme, modified hemicellulase, is produced in a microbial fermentation process. The identified enzyme has been selected as the best from a collection of several engineered enzymes available. Data presented from the lab and field show enzyme activity at various pH, temperature, and salinity conditions. The enzyme remains active at mild temperatures and pH as high as 11.5. It breaks the gels of borate crosslinked guar and derivatives. The broken gel residue is comparable to residue obtained with application of conventional enzyme or oxidizing breakers.

In addition, application of this new enzyme improves the economy of well stimulation and completion at low temperatures (80°Fto 120°F).
Production Data Indicate Reservoir and Fracture Performance in the Spraberry
Authors: Blauer R. E. , Onat I. N. , Lemieux M. J.
Published: December 2007

A study evaluating production performance of 120 Spraberry Trend wells fractured with different quantities of sand is described in this paper. The analysis is based upon Locke and Sawyer's type-curve which was developed for wells with infinite conductivity, hydraulic fractures and constant wellbore producing-pressure. History matching actual rate-time data with the type-curve provides calculated formation permeability, hydraulic fracture half-length, and estimated future recovery.

It is concluded that low permeability Spraberry Trend wells fractured with 300,000 to 320,000 pounds of sand will produce an average of 49.0 MBO and 129.1 MMCFG. When fractured with 400,000 to 450,000 pounds of sand, the average production is increased to 76.2 MBO and 190.6 MMCFG.

It is further concluded that: Each Spraberry Trend well has a unique decline curve which is strongly influenced by the hydraulic fracture.The product of reservoir permeability and propped fracture height is the most significant factor in determining the ultimate recovery from each well.A significant difference in monthly production rates from wells fractured with unequal quantities of sand is not observable until after 3 to 5 years of production.

The application of the type-curve is demonstrated by an example.
The Use of SCADA Systems in Well Testing Operations Using Submersible Pumps
Authors: Lannom R. W. , Henson F. D. , Divine D. L. , Sevin B. A.
Published: December 2007

The use of Supervisory Control and Data Acquisition (SCADA) – Satellite (SAT) systems in the petroleum industry is becoming more valuable and more widely applied every day. This paper presents an overall description of the technology employed, the hardware and software required, and the utilization of the SCADA-SAT system in well testing operations using variable speed drives and electric submersible pumps. Case histories are presented to show the type of data collected and how this data is useful in aiding well operators to properly select the correct type of artificial lift needed to properly and efficiently produce the well. The procedures needed to set up the system, establish communications, and debug hardware and software are presented. Charts, tables, and graphs are shown to illustrate the type of data generated and processed. Interaction between the central unit at the office and the field units will be described to show the functions and operations of each. Finally the benefits and drawbacks of the SCADA-SAT systems will be discussed and evaluated. The paper will conclude with descriptions of the features, functions, and benefits of using SCADA-SAT systems in conjunction with well testing operations utilizing variable speed drives and electric submersible pumping systems.
Use of Computer Model To Perform Post-Job Analysis of Automatic Control System on Fracturing Blenders
Authors: Stephenson Stan
Published: December 2007

This case history paper presents a method of analyzing fluctuation of sand concentration in a remotely controlled, automated fracturing system. In this case, job data taken from an automated and remotely controlled frac job was input to a computer model to help analysts determine the source of sand concentration fluctuations that occurred during the course of the job. The resultant computer output led the analysts to conclude that fluid agitation was inadequate for mixing 22 pounds of sand per gallon of slick water.

As a result of this successful application, the computer model is being investigated for use during automated frac jobs to provide a constant analysis of several operational criteria so that corrective action may be taken during the course of the job. This would supplement the real-time checks and recommendations already built into the automated fracturing system.

Subject paper presents program features, analytical techniques used, and discussion of other possible applications of this technology.Use of this type of analysis should result in quality improvement in fracture operations.
Feasibility Study of CO2 Stimulation in the West Sak Field, Alaska
Authors: Bakshi A. K. , Ogbe D. O. , Kamath V. A. , Hatzignatiou D. G.
Published: December 2007

The West Sak Field is estimated to contain 25 billion barrels of heavy oil-in-place. Like Prudhoe Bay field, which contains 23 billions barrels of oil-in-place, the West Sak is potentially another super-giant filed located on the North Slope of Alaska. The West Sak crude oil of 14 – 22.5 °API gravity lies at depths ranging from 2500 to 4500 feet below sea level.

A waterflood pilot conducted by ARCO Alaska, Inc. in 1984-86 showed that the recoverable reserves by primary and waterflooding methods would be very low because of the absence of a natural drive mechanism in the West Sak Field and the high reservoir oil viscosity which ranges from 50 to 3000 cp. Thus, the field is considered a target for enhanced oil recovery (EOR) processes. A preliminary EOR screening study showed that CO2 stimulation is a promising EOR process for the West Sak oil field. The CO2 required for cyclic stimulation can be obtained from the natural gas of the nearby Prudhoe Bay field which contains approximately 12% CO2.

In this paper, cyclic CO2 stimulation in the West Sak field is investigated using numerical simulator. The objectives of the study are: (1) to evaluate the performance of the cyclic CO2 stimulation versus primary depletion in the West Sak; (2) to perform a sensitivity study in order to identify the parameters governing the CO2 stimulation process, and predict the effects of these parameters on oil recovery, including such parameters as CO2 slug size injected per cycle, number of cycles, length of soak period, back pressure during production, oil and gas saturations; and (3) to determine the feasibility of CO2 stimulation process to improve the recovery of oil from the West Sak sands.
EOR for California Diatomites: CO2, Flue Gas and Water Corefloods, and Computer Simulations
Authors: Fong W. S. , Tang R. W. , Emanuel A. S. , Sabat P. J. , Lambertz D. A.
Published: December 2007

This paper describes a research project to determine oil recovery potential by CO2/flue gas injection for the Lost Hills diatomite reservoir. Gas injection into the diatomites may provide an altemale recovery method to waterflood and primary depletion. The present study is aimed at the possibility of future CO2 supplies becoming available from pipeline or from large-scale CO2 separation facilities.

The laboratory results reported here arc from a series of long coreflood studies for gas and water injection into a diatomitc rock. Coreflood models were matched to the experimental data to validate PVT data and develop numeric models for prediction of overall oil recovery for a five-spot pattern element. The hybrid streamtube method was used in the pattern simulation, Coreflood results and computer simulation indicate that CO2-flooding the diatomite reservoir after primary depletion may be technically feasible and can recover incremental oil over waterflood, both as secondary or tertiary processes with 2 to 3 times the injectivity of water.
Gravity-Induced Drainage from Fractured Porous Media
Authors: Stones E. J. , Marsden S. S. , Zimmermann S. A.
Published: December 2007

Experimental results for flow rates and production from gravity drainage experiments involving water and aqueous surfactant solutions are presented. Computer Aided Tomography (CAT scan) results are also given which show through vertical saturation distributions that significant capillary connectivity occurs across horizontal fractures during drainage. Flow rate and cumulative flow are shown to be increased by lowering the surface tension of the liquid undergoing drainage. Some theoretical discussions of the mechanism of drainage across such horizontal fractures are presented, leading to the proposal of effective area as a parameter for simulation of flow in fractured porous media.
New Results on Decline Curves Considering Non-Darcy Flow Effects
Authors: Camacho-Velazquez Rodolfo , Vazquez-Cruz Mario , Padilla-Sixto Roberto
Published: December 2007

Most of theoretical work on decline curves considering non-laminar flow is related with dry gas systems. The purpose of this study is to analyze decline curves considering non-Darcy flow effects in the reservoir for both slightly compressible liquid flow and solution gas–drive systems keeping the wellbore pressure constant.

The transient and boundary–dominated flow periods are examined by means of computer results generated with a finite difference black–oil reservoir simulator with a variable bubblepoint formulation. The consequences of this formulation under non–Darcy flow are studied.

The influence of the mechanical skin factor on the rate response is documented. For the case of liquid flow, it is presented for the first time an expression to evaluate the total skin factor which is a function of the mechanical skin and the skin due to inertial forces. This expression is given in terms of physical properties of the system, it is proportional to the square root of the pressure drop, and it is also equal to the square root of the Reynolds number. This is one of the main findings of this work.

It is investigated the possible presence of a semilogarithmic straight line of reciprocal rate for both liquid and solution gas–drive systems, and new insights are provided. In general, when the inertial effects are important and the bottomhole wellbore pressure is kept constant, a true semilogarithmic straight line of the inverse of oil rate does not develop. This result is valid for both liquid and solution gas-drive systems, and it is an important difference with the case of liquid flow under constant oil rate production mode, where a semilog straight line of the pressure drop is evident during the transient period for a big enough drainage area.

For liquid flow an apparent straight line may be fitted and its ordinate to the origin is approximately equal to the value of total skin computed with the expression mentioned above.

The presence of inertial effects distort the shape of the laminar decline curves for both multiphase and slightly compressible liquid flow, causing that type curve analysis yield wrong estimates of the wellbore and reservoir parameters. Also, if someone attempts to do a history match with data affected by non–Darcy flow using a conventional simulator, that uses Darcy's law in its formulation, an alteration of the reservoir properties will be necessary.
Field Performance of Steam Injection Profile Control using Limited-Entry Perforation
Authors: Chiou R. C. S. , Owens J. D.
Published: December 2007

Limited entry perforations have been used as a completion technique in steam injection wells to improve profile control for stratified heavy oil reservoirs. This technique is a practical application of critical flow of steam through chokes. Under critical flow conditions, the injection rate through each perforation reaches a maximum value that is independent of the downstream conditions. Therefore, no single perforation or sand can act as a thief zone. However, a fieldwide analysis of limited entry performance revealed wide discrepancies between actual and theoretical design injection rates and steam injection profiles have not always been uniform.

This paper examines the theoretical framework for both critical and subcritical flow through chokes. The limited entry theory based on ideal gas in isentropic flow process agrees well with experimental results, indicating the theory is valid under test conditions. However, the flow of wet steam in limited entry perforated injection wells under reservoir conditions can be quite different from theoretical calculations assuming critical flow. The wide spread of field data can be attributed to two factors: variation between designed and actual wellbore mechanical conditions and existence of subcritical flow conditions due to high pressure downstream of the perforation.

A new surveillance method using steam step rate test has been developed to help diagnose the bottomhole injection conditions. In many cases the tests have been used successfully in the field to 1) identify critical and subcritical flow, 2) determine the downstream pressure, and 3) identify a perforation impairment problem without running a steam-injection survey.

A simple two-layer well model has also been developed to evaluate the impact of permeability contrast on profile control using limited entry perforations. The model demonstrated that limited entry perforations can not ensure successful elimination of poor injection profiles in multisand completions in highly heterogeneous reservoirs. When permeability contrast is too large and the downstream pressure is too high, application of limited entry perforating technique is limited.
A Single-Well Tracer Test to Estimate Wettability
Authors: Ferreira L. E. A. , Descant F. J. , Delshad Mojdeh , Pope G. A. , Sepehrnoori Kamy
Published: December 2007

A single-well backflow tracer test to estimate reservoir wettability has been developed. This test consists of the injection of first brine containing tracers and then oil containing tracers. The tracers used are esters, similar to those used in the measurement of residual oil saturation, and nonreactive aqueous and oleic tracers for material balance control. The esters hydrolyze during a shut-in time and then the well is produced. The tracer production data, water cuts, and bottomhole pressures are all sensitive to wettability-dependent properties. -The most important by far is relative permeability, but capillary pressure and mixing behavior (dispersion and capacitance) are also important In the absence of fluid drift, reservoir properties such as permeability and porosity have little influence in the test results. From the results of the test, the preferential reservoir wettability may be directly inferred. By matching the test data using a compositional reservoir simulator, these properties can be estimated and used to infer wettability- or simply used direcdy in subsequent simulations of the reservoir performance.

We illustrate this process using a chemical flooding simulator.1-5 This is a reservoir simulator that includes the usual features of a finite-difference simulator in terms of reservoir description, plus compositional and chemical features needed for this application such as kinetics, partitioning, dispersion, and capacitance. Special care has been taken to ensure numerical accuracy. The CPU time on a CRAY Y-MP required for each simulation was: 10 seconds for a ID-radial (31 blocks), 3 minutes for a 2D-areal (609 blocks), and 9 minutes for a 3D (1827 blocks) simulation, so many cases can be affordably studied.
Petroleum Reservoir Characterization by Perfluorocarbon Tracers
Authors: Senum G. l. , Fajer Ruby , De Rose W. E. , Harris B. R. , Ottaviani W. L.
Published: December 2007

Perfluorocarbon tracers (PFTs), a class of six compounds, were used to help characterize the Shallow Oil Zone (SOZ) reservoir at the Naval Petroleum Reserve in California (NPRC) at Elk Hills. The SOZ reservoir is undergoing a pilot gas injection program to assess the technical feasibility and economic viability of injecting gas into the SOZ for improved oil recovery. PFTs were utilized in the pilot gas injection to qualitatively assess the extent of the pilot gas injection so as to determine the degree of gas containment within the SOZ reservoir.

Four different PFTs were used, two were injected over a days duration (approximately 12 grams of each) into a well undergoing 250 MCFPD of gas injection and the other two tracers injected over a days duration in another well undergoing 75 MCFPD of gas injection. Samples were collected from at least eighteen sampling wells surrounding the injection wells; collected at the wellhead in 1 liter sampling bombs and transferred at the NPRC site to smaller Capillary Adsorbent Tracer Samplers (CATS) which were then shipped to Brookhaven National Laboratory (BNL) for tracer analysis. Up to six tracers can be simultaneously analyzed within fourteen minutes down to a detection limit of several femto-liters of tracer per liter of reservoir gas.

PFTs have been detected in at least thirteen of the sampling wells over several months of sampling. Results will be discussed in qualitative terms of reservoir characterization since the design of the experiment does not allow quantitative certainty in reservoir interpretation. The tracer program has suggested changes in the geological interpretation of the reservoir since faulting affects the movement of the tracer tagged injection gas.

This work demonstrates that a relatively simple tracer program can be used to improve reservoir characterization.
Enhanced Oil Recovery for Independent Producers
Authors: Martin F. D.
Published: December 2007

This paper presents a survey of enhanced oil recovery (EOR) technologies with an emphasis on methods currently of major importance to independent producers. The survey quantifies oil recovery as a percent of- original oil-in-place, and documents EOR efficiency for each of the major methods.

Low to moderate crude oil prices over the last five years have limited the widespread application of EOR methods. Both improved technologies—including better process efficiencies— and properly designed tax incentives are required to stimulate the implementation of new EOR projects. Several states have enacted- or are considering tax incentives for EOR; federal legislation that included incentives for EOR went into effect in 1991. Highlights and status of both federal and state incentive measures are provided.

Several state-funded efforts are underway that can assist independent producers with EOR as well as other new technologies. Efforts in progress- or planned at the state level are outlined. These efforts range from laboratory research to technology transfer activities.

The U.S. Department of Energy recognizes the need to have EOR technology implemented by independent producers. This paper provides a summary of the programs now underway and planned at the federal level.

Because of the large front-end investment and complicated nature of many of the EOR processes, some of these methods are less attractive to independent producers, even at higher oil prices. For other techniques, sufficient technology is available and processes can be implemented by operators of any size. Most of the studies conducted to date on the future of enhanced recovery apply to large, major oil companies. The paper shows that the criteria used for implementation and the future of EOR may be quite different for independent oil producers.
Evaluation of a South Louisiana CO2 Huff ’n’ Puff Field Test
Authors: Schenewerk P. A. , Thomas Jacob , Bassiouni Z. A. , Wolcott Joanne
Published: December 2007

A DOE-sponsored field test of the cyclic CO2 injection process was conducted by members of Louisiana State University's Petroleum Engineering Department in conjunction with an independent operator. The test well was the Frank J. Bollich, et al. No. 5, located in Acadia Parish, Louisiana, and operated by Southwest Gas Producing, Inc. The well was' drilled in December, 1987, and completed in the 4500 ft. Channel Sand of the Bayou Mallet Field. This reservoir has a 17 ft. oil zone overlying an 83 ft. water zone. Prior to CO2 injection, the well was producing on a pump at a rate of 17 BOPD and 160 BWPD.

Approximately 120 tons CO2 were injected into the well on July 1, 1991. After injection, the well was shut-in for a soak period, and production was resumed on July 29, 1991. The well produced only gas for three days, then production ceased and the well was placed on a pump. Fluid production has been impaired due to the formation of a CO2, oil, water foam/emulsion. Current production is 15 bbl fluid per day, with 10 STB oil and 5 bbl water.

Air emissions were monitored during CO2 injection and production. Atmospheric CO2 levels were elevated for only a short period of time during CO2 injection and during the first two days of production. After the second day of production, atmospheric CO2 levels returned to pre-test concentrations.
The Adsorption and In-Situ Rheological Behavior of Xanthan Solution Flowing Through Porous Media
Authors: Huang Yaduo , Sorbie K. S.
Published: December 2007

The dynamic adsorption and in situ rheological behaviour of xanthan biopolymer flowing through porous media have been investigated. Results are related to the depleted layer effect, where polymer/pore wall interaction due to steric hindrance leads to a lower Newtonian apparent viscosity than bulk Newtonian viscosity. Previous work on the depleted layer phenomenon has been presented considering the effects of polymer concentration over the very dilute regime, pH and salinity on xanthan rheological and transport behaviour in porous media. Experimentally, the apparent viscosities of xanthan solution flowing in the ballotini glass bead packed columns were measured under various conditions and compared with the corresponding bulk viscosities. The experimental data were analysed using simple analytical models (two-fluid model and linear layer model) in- order to estimate the apparent depleted layer thickness. The results presented in this paper extend some of our earlier findings on the effect of both polymer concentration and salinity on the apparent depleted layer thickness. The main new results presented in this work concern the effect of xanthan dynamic adsorption on the in situ polymer rheology and depleted layer thickness. The depleted layer effect is measurable both before and after dynamic adsorption has reached equilibrium. However, the additional effect of the adsorbed layer close to the pore wall is small indicating that xanthan molecules are adsorbed very flat against the pore wall.
Numerical Investigations of Steam and Hot-Water Flooding in Fractured Porous Media
Authors: Jensen T. B. , Sharma M. P. , Harris H. G. , Whitman D. L.
Published: December 2007

Effective and economic recovery of oil from fractured reservoirs by steamflooding rely on thorough understanding of the physical process mechanisms. The objective of this research is to study steamflooding mechanisms in fractured porous media using laboratory experiments and mathematical modeling. The experimental results have been published previously [1-3]. A mathematical model developed for simulating laboratory coreflood results is presented in this paper. The model is a two-dimensional, three phase, thermal simulator which includes the effects of gravity, capillarity and thermal swelling. Thermal effects on capillary pressure and relative permeabilities are included. Simulation and analysis of laboratory experiments are presented. Sensitivity studies demonstrate the effects of injection rate, pressure and temperature, fracture aperture, capillary pressure, and relative and absolute permeabilities on oil production.
Outlook for Calibration of Large Grid Block Models for Miscible Flooding Applications
Authors: Gorell S. B.
Published: December 2007

This paper discussesthe outlook for Large Grid Block (LGB) models as predictive tools. The interactions between viscous fingering and heterogeneity are considered for combinations of secondary miscible, immiscible, and continuous and Water-Alternate-Gas injection tertiary miscible displacements. The approach uses detailed simulations in very fine-scale heterogeneous grids to calibrate simpler analytic and coarse grid models. It concludes that although much progress can be made in calibrating continuous solvent injection LGB models, these same models prove to be less reliable for more complicated situations, such as Water-Alternate-Gas injection. In particular, for continuous solvent injection: (1) The mixing parameter model can be calibrated with a potentially measurable indicator of heterogeneity to match secondary miscible recovery and injectivity. (2) Integrations between heterogeneity and effective relative permeability can be calibrated with this same indicator of heterogeneity. (3) These calibrations for secondary miscible and purely immiscible displacements can be combined and reasonably applied to tertiary miscible displacements. However, severe complications arise when considering Water-Alternate-Gas injection, particularly in heterogeneous systems which are not at their residual saturation. These complications result because: (1) The mixing parameter must vary with WAG ratio and cycle size. (2) The effective relative permeabilities depend on the nature of the phase being injected. In these situations, it is not possible to simultaneously match breakthrough times, recoveries and injectivies using a single set of LGB parameters.
Profile Control in Virginia Hills EOR Injectors
Authors: Jones P. W. , Baker R. O.
Published: December 2007

The ability to control solvent placement is critical to the success of any tertiary miscible flood in a stratified reservoir. In 1989, Shell Canada implemented a hydrocarbon flood in a heterogeneous Devonian reef at Virginia Hills. Injection profiles in this field are dominated by high permeability streaks. Since the miscible flood began, injection profiles have been improved using both mechanical methods and chemical blocking agents, resulting in increased oil and decreased solvent production.

Nine wells have been completed with mechanical profile control equipment. Multi-packer completions with different-sized- orifice valves allow control of injection volumes into each layer. Mechanical design details are presented and resulting field performance is discussed.

The philosophy and design of chemical profile control treatments are discussed. Prior to implementing chemical profile control, industry experience was reviewed and modified to improve the probability of success. The details of three chemical treatments are given in the paper.
Case History of South Belridge, California, In-Situ Combustion Oil Recovery
Authors: Ramey H. J. , Stamp V. W. , Pebdani F. N. , Mallinson J. E.
Published: December 2007

Pilot in-situ combustion oil recovery operations began in the South Belridge Field in 1963, and commercial operations began on a 164-acre area in 1964. This operation ended in 1986 when an air compressor failed. South Belridge oil in place of a third of billion barrels of oil with an estimated 8 percent recovery inspired interest in thermal oil recovery in 1947. This study presents results of 22 years of commercial in-situ combustion at South Belridge.

Although continuous steam injection is the most important thermal oil recovery operation in South Belridge, in-situ combustion offers opportunity for extending thermal operations in other fields far beyond bounds appropriate for steam injection. Results at South Belridge for both commercial steam injection and in-situ combustion have been published. Steam injection is among the best in California, and in-situ combustion is considered average for California conditions.

At South Belridge, the surface energy requirement per barrel of oil produced by in-situ combustion was about one fifth that required for steam drive. The pounds of flue gas generated per barrel of oil recovery from in-situ combustion was about half that required for steam drive. Emulsions were produced by in-situ combustion, but posed no special problems. Well failures for in-situ combustion were similar to those for steam drive once old (pre-1964) completions were replaced.

The ratio of cum. inj. air to cum. prod. oil was 3.7 MCF/BBL, about a third of the design ratio. In-situ combustion offers an efficient extension of thermal enhanced oil recovery to deep, high-pressure, low-oil-reactivity formations.
The Effect of In-Situ Pore Pressure on MEOR Processes
Authors: Jenneman G. E. , Clark J. B.
Published: December 2007

Most laboratory work in MEOR, both in screening and in development, is performed under in situ temperatures and in brines similar to those of the target reservoir. However, the effect of in situ pore pressures in such work is normally ignored. Much of our understanding of the effects of hydrostatic pressure on microorganisms comes from studies of microbial communities at the ocean floor. Since nearly 90% of the ocean floor has pressures ranging from 10 MPa to over 100 MPa, there is a paucity of data concerning effects on microorganisms at the lower pressures found in many oil reservoirs.

In our studies of the indigenous cells from injection brine at the North Burbank Unit, we have found that pressures ranging from 0.1 MPa to 8.8 MPa can have a significant effect on pH changes, substrate utilization, end product formation and permeability reduction. In general, hydrogen ion concentrations and carbohydrate utilization rates increased with increasing pressures. Methanol was found to be a significant end-product in the presence of hydrostatic pressure but found to be absent under atmospheric conditions. The fact that some of the observed effects could be demonstrated by simply reducing the gas headspace suggests that gas solubility could be an important factor. Gas formation in a core was estimated to account for as much as 50% of the permeability decrease observed in cores run under atmospheric pressure. Therefore the changes observed are of such magnitude as to alter the MEOR process in the reservoir from that indicated by laboratory studies not done under pressure.

Our results strongly suggest that all MEOR studies pertaining to a known reservoir should be evaluated under the in situ conditions of the reservoir, including pressure.
Iran's Petroleum Industry (Situations and Prospects)
Authors: Ebneyousef M. H. , Bogart A. J.
Published: December 2007

During the past several years Iran's potentials have been forgotten or ignored by the outside world mainly due to misconceptions, fears, and political concerns attributed to the religious overtone. The intention of the authors is to present a broad and general introduction to the new realities of regional, as well as global geopolitics and the main political and economic aspects of Iran's huge and growing petroleum industry.

The fact of the matter is that in the rapidly changing world order the need for a true stability in the region and a global cooperation has been recognized by Iran.

The country, with a population of 60 million, is now preparing itself for the major political and economic role thrust upon the nation by the socio-economic changes in the integrating Europe; the outcome of the Iran-Iraq and the Persian Gulf wars, including the likely instability of the autocratic governments of Arab states of the region; the breakup of the former Soviet Union; and market changes in the Far East. Consequently, in recognition of the internal and external needs, Iran is expanding relations with the outside and expects to rebuild and develop its economy with the assistance of the industrialized nations for mutual benefits.

Understanding and recognition of these changes is the idea, for which the time has come.
Gas Contracting Following the Introduction of Competition into the U.K. Gas Market
Authors: Aron David
Published: December 2007

The paper discusses the changing nature of gas contracting in the UK. As background the paper will review the advantages and disadvantages of the old system of gas sales. Finally the paper seeks to address some of the new opportunities and problems that are arising under the new competitive arrangements.
A Review of Oil and Gas Reserve Acquisition Activity and Its Contribution to Company Performance
Authors: Johns C. E. , Gailey J. D.
Published: December 2007

This paper analyses the contribution which reserve acquisition has made to the ability of a representative group of Oil Companies to replace their total reserve base over the 5 year period 1986-1990. It comments on the relative costs of replacing reserves through Acquisition compared to Exploration. The inadequacies of cost/bbl as the sole measure of Acquisition effectiveness are recognised and a value related measure is proposed which could be of general applicability to acquisition assessment. This approach is applied to 20 Acquisition examples which have taken place, mainly in the UKCS, over a similar time period, identifyinq the ability of the acquirer to realize value. The results indicate, as might be expected, that the individual acquisitions vary significantly in the value to the acquirer both at acquisition and subsequently. Several factors which influence the ability of the acquirer to realize value are investigated. It is argued, that the ‘premium’ ascribed to acquisitions in the UKCS is declining over time.
Integrated Reservoir Description
Authors: Holden Lars , Omre Henning , Tjelmeland Håkon
Published: December 2007

The main challenge in reservoir description is to integrate the different data sources and in particular be able to handle the uncertainty in the reservoir description. This paper presents a stochastic approach which integrates the different data sources. The method presented may be used for improving the predictions of the performance and for assessing the associated uncertainties. The latter is, however, a more complicated task.

The method consists of a combination of many different techniques, each of them used to model particular reservoir phenomena. The examples shown includes the use of Gaussian random fields, marked point processes and Markov random fields and the respond variables are hydrocarbon in place, oil production and recovery factor.
High-Resolution Schemes for Conservation Laws: Applications to Reservoir Engineering
Authors: Pinto A. C. C. , Corrêa A. C. F. , Cunha M. C. de Castro
Published: December 2007

Standard finite-difference reservoir simulation considers single-point upstream weighting to approximate the components of the convective flow term at the interfaces between blocks. This procedure stabilizes the numerical solution, but introduces high levels of numerical dispersion, making difficult the correct interpretation of the simulated results.

Exponential schemes are reasonable when diffusion dominates, but, as we show in this work, reduce to the single-point uspstream scheme when flow is too convective. A new and simple expression for the finite-difference form of linear conservation equations is derived for the exponential schemes.

Higher-order methods, like Leonard scheme, are able to reduce the numerical dispersion, but may produce non-physical solutions when the conservation equation assumes a hyperbolic form. We demonstrate, through the numerical solution of some classical non-linear equations, that this occurs because the entropy condition is violated. The numerical solutions also show that Total Variation Diminishing (TVD) methods, recently introduced in the reservoir simulation area, have the remarkable property of producing high resolution solutions which respect the entropy condition, and, consequently, are physically consistent.

The main mathematical principles for conservation laws are summarized and a screening procedure to be followed by new numerical methods is detailed. The performance of various numerical methods is analyzed for some standard reservoir engineering problems: 1D convection-diffusion equation, Buckley-Leverett equation and 2D single-phase tracer flow. Stability is analyzed. TVD schemes were also implemented on a two-phase black-oil model, considering IMPES, semi-implicit and fully-implicit formulations. We also included options of tracer injection in the water phase, considering full dispersion tensor and adsorption with the rock. Comparisons are made with refined grid single-point upstream solutions and with semi-analytical solutions. Grid orientation effect is also investigated.
A LOTUS® Template for Calculating Well Logs
Authors: Mitchell R. J. , Taylor S. J.
Published: December 2007

Calculation of well logs is a time consuming process. This template uses input parameters which consist of well name, location, county, state, formation name, starting depth, repeat interval, resistivity of shale, and irreducible bulk volume water which provides heading information for print outs. Required information from basic well logs are porosity, conductivity (optional), formation resistivity, resistivity of the formation water for the zone being calculated, resistivity of the mud filtrate, the porosity cutoff for pay in the zone being calculated and the salt water saturation cut off for the pay zone. These parameters are used to calculate apparent water resistivity, salt water saturation, bulk volume water, ratio of apparent water resistivity to input water resistivity, irreducible salt water saturation, resistivity volume of shale and a derived porosity value. A hard copy print out of the results is available through the Lotus® (Lotus® is a registered trademark of Lotus Development Corporation) print function. Using this template allows maximum control of the input parameters and reduces hand calculation time.