bluuebunny/crossref_metadata_2025 huggingface dataset:
Patents Aid Research Utilization
Authors: Hawley Paul F.
Published: December 2007

Inventions are an important product of research. They are not automatically used, even when improvement has been demonstrated.

In petroleum exploration and production, many operations such as well logging, drilling, well completion, etc., are not ordinarily carried out by the oil companies. Inventions in such lines usually must be licensed to service companies. Frequently such licenses accelerate commercialization much beyond in company development.

Service companies find their own inventions can be applied more readily with patent protection than without.

Ordinarily an independent researcher can only profit from a new idea by selling or licensing his patent.

Discussion

Most research workers do not deliberately try to invent. They try to find a reasonable answer to a problem. The new method, or apparatus, or composition, which is a suitable answer to his problem may already be publicly available. However, frequently no one has thought of it before. Such a solution is patentable. To the research worker this may be of only academic interest, unless he works for himself. If (as the usual case in the petroleum industry) he is an employee, the fact that it is capable of being patented may be of great practical importance.

Research results just do not get automatically used. The situations in which the world is waiting to beat a path through the woods to the home of the better mouse trap maker are extremely few and far between. Often the attempts of the innovator to get his new idea in use are met with indifference; frequently with active opposition. Anyone who holds a job is usually proud of his work. He owes his position to the fact that he does it competently, why should he risk his reputation to try some new-fangled idea? It is frequently observed, and I think truly, that most of us resist change. Change represents insecurity. Let somebody else try the new idea. At this point, the innovator finds himself, or his supervisor, in the role of salesman. Now innovators are not necessarily gifted with diplomacy nor the instinctive ability to share the other man's thoughts which characterizes a good salesman. Accordingly, it may be very hard to get cooperation. If the innovator in despair attempts to get the general management to ramrod the new idea, he frequently finds he has merely set up additional hurdles. It is in this situation where the patentable nature of his new idea may be of much greater importance than he visualizes.

Obviously the mere existence of a patent opens no doors. However, the existence of the patent does offer an advantage, since it automatically offers the opportunity of enabling companies or individuals during its life to make a profit where they otherwise could not. This, of course, immediately enhances the interest of some people in the results of this research.

Let us narrow consideration for a minute to the research worker in the laboratory of an oil company who comes up with a new and patentable improvement.
Exploration and Production Wastes and Class II Injection Wells: Current Regulatory Developments
Authors: Worrell D. G.
Published: December 2007

Regulation of oil and gas exploration and production wastes and of Class II injection wells (those that inject produced brines and drilling fluids) could become more rigorous in the next several years. First, many of the wastes associated with oil and gas activities, including those disposed in Class II wells, may come under increased regulatory control. Presently, most oil and gas wastes are "exempted" from the severe requirements of the hazardous waste regulatory program. Other wastes from exploration and production activities, however, are not exempted and may potentially be subject to hazardous waste regulation. The U. S. Environmental Protection Agency (EPA) has recently "clarified" the scope of this exemption with respect to wastes associated with crude oil reclaimers, service companies, and gas plants and feeder pipelines. Moreover, Congress has been debating the reauthorization of the Resource Conservation and Recovery Act (the federal hazardous waste management statute), and one of the key issues is whether oil and gas wastes should be subjected to further regulatory control. In addition, the Railroad Commission of Texas has draft proposed rules on regulation of hazardous oil and gas wastes, which will impose additional regulatory standards and controls over such wastes. Second, EPA has been considering changes to the Class II injection well program. An Advisory Committee was assembled and was composed of representatives of major and independent oil companies, environmental interests, and state and federal regulators. The EPA has evaluated the Committee's recommendations and has drafted a proposal for additional Class II regulations. The draft proposal includes tough new construction requirements for newly drilled or converted Class II wells; added monitoring and testing requirements; and additional area of review requirements that would apply to both new and existing wells. The EPA may formally propose these rules in the Spring of 1994, and they could be finalized by Summer 1995.
The OSHA File System: The Basis for Maintaining OSHA Compliance in Oil and Gas Production Operations
Authors: Clark D. E.
Published: December 2007

Adapting and implementing OSHA requirements in oil and gas production operatioris is an on-going challenge. To address this, Exxon's Southwestern Division developed and implemented an OSHA File System in all division field offices. The file system includes required written programs and records, inspection and compliance procedures, health surveys, and training records. It details inspection and training frequencies and provides a mechanism for the field to schedule and document the periodic activities mandated by OSHA regulations. The intent of the file system is to promote employee awareness of OSHA requirements so that they will be able to recognize and correct deficiencies as part of their routine activities. All of this will promote overall OSHA compliance in the field.
Automatic History Matching for an Integrated Reservoir Description and Improving Oil Recovery
Authors: Sultan A. J. , Ouenes Ahmed , Weiss W. W.
Published: December 2007

Infill drilling is a common approach to improve oil recovery in the Permian Basin. The economical success of such projects depends on the guessed reservoir characterization. In this paper, the impact of infill drilling locations on oil recovery is discussed. The major characteristic of this study compared to previous work is the reservoir description used to select the infill locations. The reservoir was totally characterized by using an automatic history matching algorithm that solves an inverse problem using the simulated annealing method (SAM). The major advantages of this approach are: 1) it can estimate a large number of reservoir parameters and 2) it is able to integrate various disciplines, such as geology, petrophysics, and reservoir engineering. The parameters estimated from a recent study for the pilot area of the East Vacuum Grayburg San Andres Unit (EVGSAU) were discussed for designing infill and waterflood projects.

The oil saturation map obtained at the end of waterflood period helped in locating interwell areas with a high saturation of mobile, unswept oil as potential infill drilling locations. By combining the oil saturation map with other parameters estimated by the inverse model, isolated infill locations were suggested in the pilot area. The incremental oil recovery of various schemes of infill and waterflood are compared. It appears that infill drilling locations selected with scientific criteria do improve the oil recovery of a very heterogeneous reservoir.
Critical Scales, Upscaling, and Modeling of Shallow-Water Carbonate Reservoirs
Authors: Wang F. P. , Lucia F. J. , Kerans Charles
Published: December 2007

High-frequency cycles and rock-fabric units are the two important scales for modeling shallow-water carbonate reservoirs. A reservoir model of the Seminole San Andres Unit (SSAU) was constructed that incorporated the high-frequency sedimentary cycles that compose the geologic framework and identified the rock fabric types of the principal flow units. Three rock-fabric units are used: dolograinstone, grain-dominated dolopackstone and medium crystalline mud-dominated dolostones, and fine crystalline mud-dominated dolostones. Rock properties such as capillary pressure and relative permeability are grouped according to rock fabric. Sensitivity studies and history matching in a two-section area of the SSAU suggest that rock-fabric-averaged models provide fluid saturation distribution more accurately than do cycle-averaged models.

The use of rock-fabric-dependent properties (initial water saturation, residual oil saturation, and relative permeability) in simulation predicts lower waterflood recovery. For carbonates with separate-vug porosity, waterflood recovery decreases and residual oil saturation increases with increasing vuggy porosity ratio (VPR). Residual oil saturation determined by the steady-state method is significantly lower than that determined by the unsteady-state method.

Upscaling permeability values into simulation block sizes was investigated using outcrop and core data. Using detailed minipermeameter data from outcrop it can be shown that the variogram range increases and the sill decreases with increasing horizontal block size. Effective vertical permeability of the simulation block is normally estimated using the ratio of harmonic mean to arithmetic mean of permeability. An analytical equation shows that this ratio is a function of variance rather than thickness.

History matching of primary production in a two-section area of the SSAU is dominated by vertical permeability, which controls the fractions of gas flowing vertically. In order to match production history, the vertical permeabilities used in the simulation are much lower than those measured from cores.
Evaluation of Gas Well Fracture Stimulations Using New Production Profiling Method
Authors: Magalski M. J. , Carlson N. R.
Published: December 2007

One common method of diverting a fracture treatment is the limited entry technique. A possible drawback of this technique, however, is the lack of diversion due to erosion of perforations by proppant, ineffective perforations, or plugging of perforations during the treatment. After using this technique for over a decade, production response on newly recompleted and fracture stimulated wells raised the issue of possible inadequate treatments. To fully evaluate the effectiveness of these treatments, a new fluid profiling method was utilized to accurately determine the contribution of multiple sand stringers before and after treatment. This profiling method confirmed the limited entry technique as a viable option for successful fracture stimulations.
Characterization of Flow Units in Sandstone Reservoirs: La Cira Field, Colombia, South America
Authors: Canas J. A. , Malik Z. A. , Wu C. H.
Published: December 2007

This paper presents a new and practical methodology to identify the flow units in a mappable geological formation. This approach uses Interwell Flow Capacity Index (IFCI) to describe the flow unit. IFCI is defined as the ratio of actual flow rates (production or injection) in any two wells in a producing unit, with the higher fluid flow rate of the two wells in the denominator. The presented approach uses core, log and production-injection data to describe the variations in reservoir connectivity. The flow units are identified and described by the use of IFCI1. A flow unit is identified by the similarities between IFCI's calculated by using petrophysical and production-injection data. A Colombian (South America) sandstone, La Cira Field "C1C unit", is used to illustrate the application of IFCI to identify and describe flow units.
The Potential for Additional Carbon Dioxide Flooding Projects in the Permian Basin
Authors: Lang K. R. , Biglarbigi Khosrow
Published: December 2007

A significant amount of incremental recovery from new CO2 miscible injection projects in the Permian Basin could be realized at oil prices between $16 and $20 per Bbl. In this analysis, major Permian Basin reservoirs were screened for their technical viability as CO2 injection candidates. Those reservoirs passing the screen were modeled using a combination of CO2 process recovery and economic models to predict incremental oil recovery and CO2 requirements under various economic scenarios. The results show that the recent resurgence of new CO2 injection projects could be sustained as long as oil prices do not remain below $16/Bbl. With the transfer in ownership of many mature Permian Basin properties which are rapidly approaching their economic limits, both majors and independents are facing the prospect of either investing in CO2 injection or abandoning the 10 to 15% of original-oil-in-place that may be recoverable by this process. A combination of low CO2 prices, government tax incentives, and innovative engineering could maintain production of this incremental oil into the next century.
Foam Processes: An Assessment of Their Potential in North Sea Reservoirs Based on a Critical Evaluation of Current Field Experience
Authors: Hanssen J.E. , Holt Torleif , Surguchev L.M.
Published: December 2007

SPE Members

This paper reviews the field experience with the use of foam for improved recovery from oil reservoirs and attempts to transfer this experience to foam processes as they might be applied in North Sea reservoirs. The review of published field trials, mainly from North America, is augmented by a simulation study on a generic North Sea reservoir, covering the foam process options of greatest relevance and their sensitivity to selected reservoir, foam, and process parameters. 30 field projects have been critically evaluated with the main objective of assessing the potential of foam in a North Sea environment. For this purpose, foam processes are categorized by the desired mechanisms of action of foam: in-depth mobility control, diversion, or GOR control in production wells. A set of target foam properties (an "ideal foam") is defined for each category. Despite the differences in conditions, the field trials allow extracting significant information relevant for the comparison. It is concluded that foam has significant potential in North Sea reservoirs. The degree of recovery improvement varies between the process options and with the degree of vertical communication between reservoir layers or units. Of the foam parameters considered, the sensitivity to mobility reduction factors is the strongest with high MRF being most favorable.

Introduction

The high mobility of gas in a reservoir may cause a number of flow problems, summarized in Figure 1. A foam confined inside the pore network has many properties that are desirable for controlling gas flow. The dispersed microstructure of pore-bridging liquid films separating individual gas bubbles gives foam its unique ability to selectively reduce gas mobility. Foam has the potential of alleviating all the problems illustrated in Figure 1. Foam has been used or considered for increasing the sweep efficiency of injected gas (vertical and aerial), for blocking and diverting injected gas from entering high-permeable zones or fractures, and in treating production wells suffering from unacceptably high gas/oil ratio (GOR) levels.

Several foam pilot tests are presently being considered for North Sea oil reservoirs. Foam is a priority topic in the on-going Norwegian IOR research program RUTH, and is studied in a dedicated subprogram. A recent RUTH-Foam report which is part of the basis for the present paper discusses potential uses of foam in the North Sea, based on a critical review of the existing field experience, mostly from open sources. A difference from other, more comprehensive (data bases such as that maintained by the U.S. DOE, is that our work contains judgements by the operators and authors in addition to "hard" data.

Foam process concepts

Three gaseous fluids are involved in foam processes; steam, CO2, various hydrocarbon gases (HC) and N2.

P. 361^
A Systems Approach to Enhanced Oil Recovery Planning in Malaysia
Authors: Egbogah E. O. , Hovdestad W. R. , Daud M. E. , Raja D. A.
Published: December 2007

It is estimated that more than fifteen billion barrels of oil will remain in Malaysian offshore reservoirs at the end of primary and secondary recovery. This considerable resource base is the target of planned EOR projects. Although contractor specific field evaluations have been carried out, no previous study has addressed the potential EOR contribution to the Malaysian reserves mix on a broad national scale attempted herein. This paper therefore examines the potential Malaysian reserves additions through the application of suitable EOR technologies. In doing so, the paper proposes a comprehensive approach to reservoir screening and selection of technically feasible and economically viable reservoir-specific EOR processes for Malaysian fields.

Results of a screening study indicate that carbon dioxide and hydrocarbon miscible gas displacement processes are the most attractive EOR technology for large scale application in Malaysian reservoirs. Data on resource evaluation, allocation and utilization of natural gases in Malaysia, have been reviewed as to the availability of injectant supplies. These data indicate that significant carbon dioxide supplies in gas fields offshore Peninsular Malaysia and surplus natural gas supplies in Sarawak and Sabah states, provide the injectant needed for commercial miscible displacement operations. Carbon dioxide injectant is preferred for Peninsular Malaysia as it is in close promixity to potential user fields, while natural gas is reserved for onshore industrial and other commercial uses.

Given certain assumptions regarding development timing and industry cooperation, it is found feasible that incremental oil reserves additions of up to three billion barrels could be achieved within fifteen years through the application of proven gas injection technology. The effects of improved reservoir management, for example, better residual oil saturation determination, improved reservoir characterization and more accurate reservoir simulation, have not been factored into this total. However, the realization of these EOR reserves will be predicated upon a broad spectrum of economic, technological and policy constraints, which will require the concerted efforts of both industry and national energy policy makers. This paper also presents details of the constraints which must be removed in order to maximize the benefits of the EOR technologies and associated reserves for Malaysia.
In-Depth Drive Fluid Diversion Using an Evolution of Colloidal Dispersion Gels and New Bulk Gels: An Operational Case History of North Rainbow Ranch Unit
Authors: Fielding R. C. , Gibbons D. H. , Legrand F. P.
Published: December 2007

The North Rainbow Ranch Unit (NRRU) is located in Campbell County, Wyoming, and produces from the Minnelusa "A" Sand. In the absence of a strong water drive, primary production from the Minnelusa is generally less than 20% of the original oil in place (OOIP). Waterflooding the Minnelusa is an accepted procedure; however, sweep efficiencies can be poor due to high permeability variation. This variation can cause rapid water breakthrough, high producing water-oil ratios (WOR's), and low injection pressures.

Polymer augmented waterflooding is utilized to improve reservoir conformance and can increase recoveries to over 45% of OOIP. Two different types of polymer-augmented systems have been used successfully on injection wells at NRRU. The first system was a long-term, in-depth colloidal dispersion gel (CDG). This process used cationic polyacrylamide and anionic polyacrylamide crosslinked with aluminum citrate. Fresh water was required for mixing. Incremental oil recovery from this process totaled 300,000 stock tank barrels of oil (STBO). The second system was a short-term bulk gel (BG) consisting of a new anionic polyacrylamide and chromium acetate combination. Produced water was used to mix the BG. Incremental oil recovery from this process is estimated at 155,000 STBO.

This paper summarizes the design and performance of both systems and discusses operational issues encountered with the polymer augmented applications at NRRU.
Effect of Pressure on CO2 Foam Displacements: A Micromodel Visualization Study
Authors: Chang Shih-Hsien , Martin F. D. , Grigg R. B.
Published: December 2007

This paper presents the results of a visualization study on the effect of pressure on CO2-foam displacements at pressures above and below the minimum miscibility pressure (MMP). CO2-foam visualization experiments were performed by simultaneous injection of surfactant solution and CO2 into a high-pressure, glass micromodel saturated with Maljamar crude oil. CO2-foam was generated in situ during the simultaneous injection of surfactant solution and CO2. Simultaneous injection of brine and CO2 (WAG) displacements and pure CO2 displacements were also conducted to provide a reference point for the CO2-foam displacements. Results of these displacements were compared to examine the effects of pressure and injection mode on displacement performance and mechanisms. Two different kinds of micromodels were used in this study: modified-layer (MLAY) and modified-heterogeneous (MHET) micromodels. Pressures ranging from 775 to 1320 psia were investigated at a system temperature of 90°F. The surfactant solution used was 1% Alipal CD-128 in a 1 % NaCl brine.

Results show that sweep efficiencies were generally lower for pressures below the MMP. However, the effect of pressure on sweep efficiency for CO2-foam displacements was less than for WAG displacements and much less than for pure CO2 displacements. Sweep efficiencies for CO2-foam displacements at pressures just below the MMP were as high as above the MMP. Due to the lower density of injected CO2 near and below the MMP compared to that at higher pressures, the required mass of CO2 was as little as one-third of that required at higher pressures for similar sweep efficiencies using CO2-foam. These observations suggest the economical potential of operating CO2-foam floods at pressures close to and just below the MMP.
Gas/Oil Lamallae and Surfactant Propagation in the Oil in Carbon Dioxide Foam
Authors: Kuhlman M. I. , Falls A. H. , Wellington S. L.
Published: December 2007

Gas-oil foam has been; observed at reservoir conditions in microvisual experiments, created in laboratory corefloods, and shown to have been responsible for CO2 and N2 mobility reduction in experiments.

Gas-oil foam can increase oil recovery, since gas mobility is reduced without a reduction in oil mobility. It occurs when oil spreads between water and gas, and oil wets solid surfaces. The surfaces may be oil wet, be wet as surfactant partitions into oil, or when a surfactant is used below its Critical Micelle Concentration (CMC).

An oil bank is more mobile than injected brine, so oil soluble surfactants move ahead of aqueous components. Modeling suggest that gas-oil foam improves oil production in a reservoir, because surfactant in the oil rises to the oil bank at the top of a reservoir, where water mobility is too low for surfactant transport.
Composition of Remaining Oil in a Mature Steamflood
Authors: Richardson W. C. , Chu Chieh
Published: December 2007

Steam distillation of reservoir oil occurs in the steam flooding process. The steam distillation phenomenon has been established and extensively studied in the laboratory, but has not been well understood in the field. The present work describes a compositional analysis of remaining oil with depth from a mature field steamflood, and supportive numerical simulation. Inclusion of the steam distillation mechanism in the analysis of the steamflood process is a potential emerging strategy for more enlightened reservoir operation and management.

Heavy stock tank oil characterization by a pseudo carbon number molar distribution and conventional analyses have been used to monitor changes in residual oil in a 70 ft mature steamflood zone in the Kern River Field, California, U.S.A. In order to obtain residual oil distributions, analysis methods were developed where the effect of the extraction solvent on oil composition determination was minimized, and assessments of the non-analyzable portion of the oil were made. The results of analyses of residual oil samples extracted from field core establish the effects of steam distillation and solvent formation in a mature steamflood.

The compositional effects on residual oil observed in the field have been supported by simulation. Numerical simulation of the cored zone was carried out using volatile pseudo components. The results showed the distribution of hydrocarbon components at various depths and grid blocks, and corroborated the laboratory work. Although this was applied to the Kern River Field, the approach has wider application to other steamfloods. The compositional effects will be even more important for lighter oil reservoirs, such as the Duri Field Steamflood.
A New Method To Characterize Fractured Reservoirs: Applications to Infill Drilling
Authors: Ouenes Ahmed , Weiss W. W. , Richardson Scott , Sultan A. J. , Gum Timothy , Brooks L. C.
Published: December 2007

A new approach in fractured reservoir characterization that integrates geomechanics, geology, petrophysics and reservoir engineering is proposed and illustrated with an actual oil reservoir. This approach uses a generalized form of the curvature method to derive a model for fracture intensity and orientation for the Young Deep Unit (YDU). A reservoir inverse model was used to convert the fracture properties into effective petrogeological attributes. The inverse model uses simulated annealing and a black oil simulator to estimate fracture directional permeabilities and pore volume, reservoir wettability, and wellbore properties. The conditioned reservoir model that matches oil, gas, and water monthly rates, and reservoir pressure for a 151 month period, was used to construct an infill drilling criterion map to locate the best infill locations in the YDU.
A Combined Use of CRYO-SEM and NMR-Spectroscopy for Studying the Distribution of Oil and Brine in Sandstones
Authors: Rueslåtten Håkon , Øren P-E. , Robin Michel , Rosenberg Elizabeth , Cuiec Louis
Published: December 2007

This paper investigates the wettability behaviour of three rock samples from a Middle Jurassic Brent Group North Sea sandstone reservoir using a combination of traditional Amott and USBM tests, Cryo-SEM and NMR-spectroscopy. From Cryo-SEM observations it is concluded that two of the samples aged in crude oil display an oil-wet to intermediate wet behaviour and that residual oil is preferentially associated with kaolinite. The third rock sample (which has a permeability of only 19.4 mD) displays a more water-wet behaviour. The intermediate wettability nature of the rock samples is also reflected in the NMR data and it is demonstrated that NMR relaxation data may provide quantitative information about the saturations of wetting and non-wetting fluids and their distribution within the rocks.
Use of Horizontal Wells for Improving Steamflood Performance of a Thin, Low-Permeability Heavy-Oil Reservoir
Authors: Sarkar A. K. , Sarathi P. S. , Strycker A. R.
Published: December 2007

About 4 ×109 bbl heavy oil resource exists in thin (20-40 ft) domestic reservoirs. For this type of reservoir, steamflooding with conventional vertical wells is not economic, and in situ combustion methods are not applied due to operational difficulties. Horizontal well technology offers a potential for improving technical and economic performance of steamflood operations. A reservoir simulation study was conducted to (1) evaluate the viability of applying steamflood operations using horizontal wells in the Charivari Creek, Arkansas, waterflooded heavy oil reservoir and (2) analyze in detail the effects of different pattern configurations, including vertical injectors-vertical producers, horizontal injectors-horizontal producers, horizontal injectors-vertical producers and vertical injectors-horizontal producers, on steamflood performance.

Low permeability was found to have the most negative influence on steamflood performance for vertical injectors and producers. The injected steam raised the pressure and temperature of the reservoir to higher values than those observed in the high-permeability reservoirs, resulting in ineffective displacement and reservoir heating. Among the different configurations tested, the horizontal injectors-horizontal producers with 1,272-ft laterals increased the cumulative oil-steam ratio to 0.2 and decreased the production cost to $12.70/STB. Comparable results obtained for vertical wells are cumulative oil-steam ratio of 0.1 and production costs of $23.50/STB. Inclined wells showed poorer performances than horizontal wells because of nonuniform displacement. Configurations using horizontal injectors-vertical producers were not as effective as vertical injectors-horizontal producers because of fluid flow difficulties created with the high injecti vity of horizontal injectors and the low productivity of vertical producers.
Injection Conformance Control Case Histories Using Gels at the Wertz Field CO2 Tertiary Flood in Wyoming
Authors: Borling D. C.
Published: December 2007

Case histories described in this paper demonstrate the technical and economic value of using a specific work process coupled with advances in gel technology to improve vertical and areal injection fluid distribution at the Wertz Field carbon dioxide (CO2) Tertiary Flood in Bairoil, Wyoming. The Wertz case histories incorporate results from ten injection well gel conformance workover repairs with fluid performance response at offset producing wells. Post appraisal findings confirmed individual pattern life for tertiary processing was extended by nearly two years resulting in incremental oil recoveries of up to 140,000 barrels per pattern.
Polymer Gels for Conformance Treatments: Propagation of Cr(III) Crosslinking Complexes in Porous Media
Authors: Bartosek Martin , Mennella Aniello , Lockhart T. P. , Causin Emilio , Rossi Elio , Passucci Claudio
Published: December 2007

The influence of pH, temperature, and gelation delaying ligands on the stability of Cr(III) complexes in bulk solution and on Cr(III) propagation in porous media has been investigated for acetate, glycolate, and malonate complexes of Cr(III). For a given complex, Cr(III) instability to hydrolysis and Cr(III) retention increase with increasing pH and temperature. The chemical nature of the gelation delaying ligands bound to Cr(III) and their coricentration in the solution have a profound influence on the resistance of the Cr(III) complex to hydrolysis and on Cr(III) retention. Thus, whereas the Cr(III) acetate crosslinker, by itself, propagates poorly at elevated temperature, addition of sodium glycolate to the solution markedly reduces retention. We show that Cr(III) retention in sandstone cores can be virtually eliminated at 90°C by appropriate formulation of the gel-forming solution. Other experiments establish that Cr(III) precipitation at elevated temperature is reversible in the presence of polymer and that significant accumulation of the Cr(III) precipitate can have a negative impact on injectivity.
Practical Implementation of Risk Analysis
Authors: Patteson R. M. , Grittner S. F.
Published: December 2007

EXECUTIVE SUMMARY

Formal Risk Analysis and Decision Theory Principles are being utilized in daily operational decisions. A PC and Macintoch software program has been developed to minimize the effort and time required for this type of analysis. The process encourages structured thinking and the documentation of the justification and assumptions used in making decisions. This approach is not designed to replace the intuitive approach to decision making but rather to augment it.

The results of the project are encouraging. This methodology is being used more often by a larger group of decision makers. Communication between project team members has been improved as the common language of probability and cost is more frequently used when discussing alternatives. The emphasis of the project is to convince potential users that problem structure and the correct layout of alternatives is the single most important component of the process.
An Analysis of Oil and Gas Property Assessment Practices Used by County Assessors in California
Authors: DeWitt B. A. , Fiddler C. D.
Published: December 2007

This paper discusses the methodology used by California tax assessors to set a fair market value (FMV) on California oil and gas properties for ad valorem tax purposes. A 265 parcel data set from 70 California independent oil and gas producers was used to look at how the assessors projected price, production, and cost data, and the basis they used to set a discount rate (DCR) for their cashflow projections in determining FMV. The study concludes that for the 1993-94 tax year county assessors did not adequately handle oil price risk, production forecast risk, or cost forecast risk in their analyses. As a result, the counties overassessed many of the parcels in the data set. An analysis of the derived market value indicators (MVFs) (i.e., payout, dollars per barrel oil equivalent reserve ($/BOE) and dollars per daily barrel oil equivalent ($/DBOE)) tends to verify the overvaluation conclusion.
Methods for Eliminating Pipeline-Riser Flow Instabilities
Authors: Jansen F. E. , Shoham Ovadia
Published: December 2007

Flow instabilities can occur in pipeline-riser systems operating at low liquid and gas rates, leading to an undesirable cyclic operation. Traditional methods for elimination of riser flow instabilities are choking and gas lift. However, each of these methods suffers from operational disadvantages. Choking can increase the back pressure, thereby, reducing production, while gas lift requires large volumes of injected gas.

The objective of this paper is to investigate existing methods and to propose a more optimum method for the elimination or minimization riser flow instabilities. An experimental study has been conducted to predict the behavior of the different methods of elimination of riser instabilities. It was found out that a combination of gas lift and choking is an efficient elimination method, reducing both the required degree of choking and the amount of injected gas required to stabilize the flow in the riser. The proposed method is less sensitive to choke setting and injected gas volume, as compared to elimination by either choking or gas lift alone. Additional advantage is the capability of a smooth and controlled start-up of the system.

This study demonstrates the usefulness of flow pattern maps as a simple and effective tool for the visualization and prediction of the occurrence of flow instabilities. Theoretical criteria have therefore been developed to predict the flow behavior for riser base gas lift and riser top choking.
Facility Optimization Through Process Review: A Case Study
Authors: Korn D. E. , Houghton M. K. , Langweil R. T. , Pauley J. C.
Published: December 2007

The current operating environment of low oil prices and high regulation is putting significant pressure on operators to reduce their costs and environmental exposures. All too frequently these costs and exposures are the result of operating practices that date back to conditions and requirements that are no longer applicable. Often improvements can be made by optimizing the processes that are currently in place. In order to achieve the greatest gains however, a company must be willing to challenge the paradigms behind their current operating practices and be willing to change or eliminate processes as necessary.

This paper will describe the process and results of a systematic review of Texaco's Kern River Field plant operations.

This review resulted in the generation of dozens of process improvement ideas, some minor and some major. The significant improvements are discussed below. The results include a more stable operation and one that is much more cost effective.
An Operator's Perspective on Through-Tubing Recompletion Technology
Authors: Fleckenstein W. W. , Garner T. A.
Published: December 2007

This paper reviews through-tubing recompletion technology, the isolation and/or addition of perforations in a wellbore without pulling the existing production equipment. Topics covered include through-tubing plugbacks and bridge plugs, coiled tubing cementing and through-tubing perforating. Several well case histories are also presented.
Reorientation of Propped Refracture Treatments in the Lost Hills Field
Authors: Wright C. A. , Stewart D. W. , Emanuele M. A. , Wright W. W.
Published: December 2007

Chevron has performed over 200 refracture treatments in the diatomite reservoir within the Lost Hills field. Most treatments have consisted of refracturing intervals originally stimulated with less than adequate fluid and proppant volumes to efficiently deplete the reservoir. Many of these refracture treatments show production and pressure responses similar to new development wells completed in "virgin" reservoir. Recently, from 1990 to 1993, four new wells (post 1986) with modem initial fracture treatments were refractured in the same intervals with treatments similar (fluid and proppant volumes) to the original fracture treatments. All wells responded with post refracture production response equal to or slightly less than that of the original treatments. On the average these wells showed production increases of 50 BOPD over the previous daily rates of approximately 10 BOPD.

An effort began in 1993 to investigate possible reasons for the apparent "virgin" production response that resulted from the refracture treatments. A number of potential mechanisms were considered, including dramatic fracture conductivity degradation of the original propped fracture treatments; greatly enhanced fracture length growth upon refracturing; and stress change induced reorientation of the refracture treatments along a different fracture plane than the original fractures. This latter mechanism was considered the most likely mechanism and a program was designed to gather the necessary data for positive determination. Because Chevron had previously utilized tiltmeter fracture mapping on over 100 propped fracture treatments in the Lost Hills Diatomite, there existed ample original fracture treatment orientation data for comparison with fracture mapping data from refracture treatments.

In the Spring of 1993 tiltmeter fracture mapping was performed on five refracture treatments. All five of the refracture treatments propagated along a significantly different orientation than the original fracture treatments in these wells. Refracturing along a different fracture plane from the original fracture plane has dramatic implications for production strategies of both primary and secondary recovery. The tiltmeter fracture mapping results, production data, calculated reservoir stress changes, and proposed mechanism for refracture reorientation are all presented in the paper.
Individual Layer Transient Tests in Low-Pressure, Multi-Layered Reservoirs
Authors: Ryan T. C. , Sweeney M. J. , Jamieson W. H. , Tanigawa J. J.
Published: December 2007

The Hugoton Field in southwestern Kansas, western Oklahoma and northwestern Texas is the largest gas field in North America. Gas production is from the shallow (2,100+ feet to 2,900+ feet) heterogeneous, multi-layered Chase reservoir. This paper details the results to date of an individual layer pressure testing program conducted by Mobil in 1992 on two wells in the Kansas Hugoton field. The recent history of pressure transient attempts in the Hugoton field is covered. How this information was used in planning the testing programs, foam drilling and coring, drill stem tests (DST), wireline pressure testing, in-situ stress and strain testing, and logging programs is explained as well as the evolution of the drilling, individual layer DST, completion, and individual layer cased hole testing operations and procedures. These wells represent the first time in recent history individual layer pressure and rate data has been measured in non-stimulated layers on any wells in the Hugoton field. The results of this test program are covered as well as how this data is being incorporated into Mobil's reservoir characterization and simulation efforts in this field. This analysis shows: (1) The pressures ranged from 142 psia to 320 psia, compared to 484 psia initial bottomhole pressure, in the five major carbonate layers in the Chase reservoir, (2) The three more permeable layers had the lowest pressure and were being effectively and efficiently drained while the less permeable layers had the highest pressure and were being effectively, and possibly efficiently drained, by original wells 2,100 feet to 3,300 feet away, (3) The wireline pressure testing results were accurate and precise, but often not representative of the layer pressures in the individual layers, and (4) The various testing operations require extra planning in a foam system due to underbalance conditions and conflicting wellbore fluid requirements.
Feasibility Study for the Drilling of a Horizontal Well in the West Panhandle Field
Authors: Taylor L. L. , Carden R. S. , Selinger K. A.
Published: December 2007

Choosing the proper application is crucial to the success of any horizontal well. Many horizontal wells drilled in the past were technical successes and economic failures. Thousands of horizontal wells have been drilled in the last five years, but most have targeted oil reservoirs with relatively low permeability and high pressures. This paper considers the applicability of horizontal drilling to a large gas reservoir with high permeability and low pressures. More specifically, it discusses an approach for evaluating the economics of drilling such a well in the West Panhandle Field
3-D Reservoir Simulation Results of a 25-Square-Mile Study Area in the Kansas Hugoton Gas Field
Authors: Oberst R. J. , Bansal P. P. , Cohen M. F. , Ryan T. C.
Published: December 2007

The Hugoton Gas Field is the largest gas field in the lower 48 states and represents a significant portion of the domestic gas production and reserve base in North America. The gas bearing Chase Group is characterized as a heterogeneous, multi-layered, no-crossflow system with over 5,925 producing wells in Kansas alone.

This paper reports the results of a three dimensional (3-D) reservoir simulation model that predicts the behavior of this multi-layered system under various producing scenarios. The 28 well pattern model covers a 25 square mile representative portion of the field called the "Nix area". The area was initially simulated in 1985 to primarily study the potential benefits of infill drilling. This earlier work is the fundamental blueprint from which today's current model is built. It was felt that by incorporating aspects of the previous study into the current model, it would provide a unique baseline to compare and contrast the earlier predictions against new data and our increased understanding of the Hugoton field, some seven years and approximately 1,660 infill wells later. The current model also contains two new replacement wells and an observation well that have been drilled since 1985. In addition, individual layer pressure data has been gathered along with the additional 10 years of production and pressure data which has occurred since the first study. Using the new model, various prediction runs were made to project each well's future deliverability, ultimate recovery and determine each individual layer's abandonment pressure, with or without infill drilling.

Results from the study indicate that the remaining life of the Kansas portion of the Hugoton field to be at least 40 to 50 years under existing producing conditions. The major gas producing layers will abandon at average bottomhole reservoir pressures ranging from 30-40 psia, while the tighter, less productive layers abandoning between 140–210 psia, regardless of infill drilling or. not. This will result in an expected ultimate recovery of between 90%–92% of the initial gas-in-place for the major producing layers, and between 58%–68% ultimate recovery in the tightest layers. The study also indicates that due to the laterally continuous nature of the geologic layers, infill drilling will result in only a period of reserve acceleration, with no significant, incremental reserves being developed.
Advances In Two Phase Flow Mechanistic Modeling
Authors: Taitel Yehuda
Published: December 2007

Rigorous exact solutions in engineering are essentially non existent. In all engineering problems one has to resort to some kind of approximations in which the physics of the problem is approximated and formulated in a format tractable by analytical or numerical means. This kind of approximation is termed MODELING.

In the quest for more accurate, but yet, sufficiently simple approaches to the solution of two phase flow problems MODELING is of utmost importance. The term "Mechanistic Modeling" was adopted for modeling where the physical phenomenon is approximated by taking into consideration the most important processes, neglect other less important effects that can complicate the problem but do not add considerably to the accuracy of the solution. "Mechanistic Modeling" should be sufficiently close to the natural phenomenon as the flow pattern involved should not be overlooked. Yet it will be sufficiently simple so that the solution is amenable with reasonable analytical or numerical efforts.

Specific examples which relate to recent developments in Mechanistic Models for two phase flow such as the prediction of flow pattern, stratified flow and the stability of stratified flow, slug behavior in pipes, slug length distribution, severe slugging phenomenon and splitting in a tee junction will be presented.
Consequence Analysis in the Production and Transportation of Oil and Gas
Authors: Norris H. L. , Hissong D. W.
Published: December 2007

In the event of a pipeline or vessel leak or rupture at an oil and gas production facility, understanding of vapor-liquid multiphase flows can be very helpful in mitigating the safety and environmental consequences. The relevant multiphase flow phenomena involve flows both internal and external to the pipe or vessel. They include the release rates of vapor and liquid hydrocarbons, the sonic flow region immediately downstream of the opening, possible generation of aerosols, and possible segregation of the efflux into a gas jet and a liquid pool. If the release does not ignite, it is important to be able to describe the dispersion of the heavy multiphase plume. If the release does ignite, the size, position, and luminosity of the resulting jet and pool fires are important. Many aspects of these flow phenomena are not well understood. A survey is made of the relevant issues, existing calculation methods, and suggested research initiatives.