bluuebunny/crossref_metadata_2025_split huggingface dataset:
Gas Research Institute Hydraulic Fracture Test Site
Authors: Robinson B. M. , Syfan F. E. , Holditch S. A. 
Published: December 2007

ABSTRACT
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

ABSTRACT
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 (&gt;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

ABSTRACT
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

Abstract
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

ABSTRACT
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

ABSTRACT
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

ABSTRACT
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

Abstract
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

Abstract
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

Abstract
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

ABSTRACT
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

Abstract
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

ABSTRACT
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

ABSTRACT
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.