bluuebunny/crossref_metadata_2025 huggingface dataset:
Enhanced Oil Production Owing to Sand Flow in Conventional and Heavy-Oil Reservoirs
Authors: Wang Yarlong , Chen Carl C.
Published: December 2007

A coupled reservoir-geomechanics model is developed to simulate the enhanced production phenomena in both heavy-oil reservoirs (northwestern Canada) and conventional oil reservoirs (i.e., North Sea). The model is developed and implemented numerically by fully coupling an extended geomechanics model to a two-phase reservoir flow model. Both the enhanced production and the ranges of the enhanced zone are calculated, and the effects of solid production on oil recovery are analyzed. Field data for solid production and enhanced oil production, collected from about 40 wells in the Frog Lake area (Lloydminster, Canada), are used to validate the model for the cumulative sand and oil production. Our studies indicate that the enhanced oil production is mainly contributed (1) by the reservoir porosity and permeability improvement after a large amount of sand is produced, (2) by higher mobility of the fluid caused by the movement of the sand particles, and (3) by foamy oil flow. A relative permeability reduction after a certain period of production may result in a pressure-gradient increase, which can promote further sand flow. This process can further improve the absolute permeability and the overall sand/fluid slurry production. Our numerical results simulate the fact that sand production can reach up to 40% of total fluid production at the early production period and decline to a minimum level after the peak, generating a high-mobility zone with a negative skin near the wellbore. Such an improvement reduces the near-well pressure gradient so that the sanding potential is weakened, and it permits an easier path for the viscous oil to flow into the well. Our studies also suggest that the residual formation cement is a key factor for controlling the cumulative sand production, a crucial factor that determines the success of a cold production operation and improved well completion.
Hydraulic Fracturing in the Caddo-Pine Island Field
Authors: Patterson B.F.
Published: December 2007

The application of the hydraulic fracturing process in the Annona Chalk formation in the Caddo-Pine Island field, Caddo Parish, La., has created a new outlook on the development of this reservoir as an economic source for oil production. The reservoir has been greatly affected by faulting and/or fracturing during its geologic history, and the physical characteristics of the formation have made possible the successful hydraulic fracturing operations. These conditions have also caused the production to vary greatly between wells and have resulted in several different methods of drilling and completion practices by the operators.

This paper describes briefly the geology, development history, present drilling and completion practices, and the results of the hydraulic fracturing process in stimulating the production from this reservoir. In order to show results of the various completion techniques, production histories on several wells are presented and comparisons of the production from individual or groups of wells before and after fracturing operations are discussed.

Introduction

The Caddo-Pine Island field is located approximately 15 miles north of the City of Shreveport in Caddo Parish, La., and Marion County, Tex., and is shown geographically in Fig. 1 which covers a portion of the Ark-La-Tex Area. Although production has been obtained from several horizons, ranging in depth from the Nacatoch sand at 800 ft to the Hosston or Travis Peak which is found at 2,500 ft near the crest of the dome of the Lower Cretaceous beds, this paper will deal mainly with the development and production of the Annona Chalk reservoir.

The production from the Chalk is associated with faulting and natural fracturing of the formation and is found in several fields in North Louisiana. The discovery well in the Caddo-Pine Island field was the Savage Bros. & Morrical No.1 Offenhauser, which was completed March 28, 1905, in the Annona Chalk at a depth of 1,556 ft. The well was located near Oil City, La., in the center of the NE ¼ of the SW ¼ of Sec. 1, T20N, RI6W, and had an initial production of 5 B/D of 34° gravity oil. The well was considered non-commercial by the operators and was soon plugged and abandoned. However, this discovery led to further development. By the close of 1907 23 wells had been drilled -eight of which produced oil, 11 produced gas, and four were abandoned. Development of the field continued at a rapid pace during the following years, and by 1918 the production reached a peak of 11 million bbl/year.
U.S. Offshore Oil and Gas Lease Royalty Bidding
Authors: Dougherty E.L. , Lohrenz J.
Published: December 2007

U.S. offshore oil and gas lease royalty bids were analyzed. Bids appear to be normally distributed. Using a simple investment model, the trade-off between bonus and royalty bids for an investor was examined. Higher royalties can result in lost recovery when (1) marginal deposits are not developed and (2) productive leases are shut in earlier.

Introduction

U.S. offshore oil and gas leases were issued exclusively as a result of bonus bids from 1954 to 1974. Since then, leases have been offered and issued to royalty bidders in two sales, although bonus bidding has remained the predominant system. With the emergence of royalty bidding, we undertook to examine the character of the royalty bids that have been submitted and to assess the impact of royalty bidding on subsequent production. In this study, we examined the statistical distribution of royalty bids. Government presale estimates of royalty bid leases were compared with royalty bids received; the results of this comparison are contrasted to the corresponding finding with bonus bids. We used a simple investment model to predict the trade-off between royalty and bonus that predict the trade-off between royalty and bonus that a bidder would bid. Finally, we examined how royalty affects recovery in two ways:decisions not to initiate production anddecisions to cease production that would continue if the royalty were production that would continue if the royalty were lower.

Statistical Analyses of Royalty Bids

The two sales in which leases were offered by royalty bidding were held Oct. 15, 1974, in Louisiana and Oct. 27, 1977, in Alaska. Of the 10 such leases offered in the Louisiana sale, eight received a total of 57 bids and all were issued. Through 1979, six of the eight leases were relinquished. Of the two leases still active, one had production starting in 1979. In the Alaska sale, 46 leases were offered to royalty bids. Of these, 30 received a total of 98 bids, and all leases receiving bids were issued. Through 1979, none of these Alaska royally bid leases were relinquished or had any production. Detailed data about these leases, the bids, and bidders are available. Fig. 1 is a plot shown on normal probability graph paper of the bids received for lease OCS No. G2905 paper of the bids received for lease OCS No. G2905 (Oct. 15, 1974, Louisiana sale). Thirteen bids were received for this lease, the largest number of bids for any of the royalty bid leases. The linearity of the plotted points in Fig. 1 is typical and suggested the plotted points in Fig. 1 is typical and suggested the hypothesis that royalty bids for leases may be normally distributed. Analogously, bonus bids have been treated as log-normally distributed. Taking the royalty bids as normally distributed, the pooled standard deviation of the bids on the 32 leases with two or more bids in both sales was 13%. Detailed statistical results have been given elsewhere. That result provides a crude but pragmatic measure of the disagreement between bidders' royalty bids.
Deployment of a Scale Squeeze Enhancer and Oil-Soluble Scale Inhibitor To Avoid Oil Production Losses in Low Water-Cut Well
Authors: Jordan M. M. , Graff C. J. , Cooper K. N.
Published: December 2007

This paper outlines the development of an effective treatment strategy for production wells that suffered significant performance impairment at water cuts of less than 5% caused by carbonate scale deposited within the electrical submersible pumps (ESPs). These Alaskan production wells had been treated for a couple of years with aqueous-based scale-inhibitor squeezes. Many of these treatments resulted in a significant reduction (10 to 20%) in the oil production rate following the squeeze. The damage mechanism was investigated by coreflooding and was revealed to be a combination of water block and relative permeability effects. Following the coreflood damage investigation, a second study was undertaken to investigate a chemical treatment to remove the damage already present within the near wellbore and to prevent further deposition of scale. The result of this test program was the development of a treatment strategy that used a solvent package followed by an oil-soluble scale inhibitor. Field results of this type of treatment suggest that the wells treated with this chemical system did not suffer any reduction in the oil production rate and were effectively protected from carbonate scale. Wells that had been damaged by the previous aqueous treatments could be stimulated, and the lost oil production could be recovered. Reference is also made to the development of improved, aqueous-based squeeze treatments for the treatment of higher water-cut wells.
Application of a Resistance Network for Studying Mobility Ratio Effects
Authors: Nobles M.A. , Janzen Harold B.
Published: December 2007

Introduction

Since 1950, several papers have been published which have described various methods for studying mobility ratio effects. The methods which have been described for studying mobility ratio effects include X-ray shadowgraph techniques, stepwise potentiometric model procedures, stepwise numerical procedures, gelatin model studies and fluid mapper model studies. The purpose of this paper is to describe a procedure for using a resistance network for studying mobility effects.

Description of Apparatus

The basic unit of the experimental model consisted of a network of 840 resistors fastened to a sheet of black Lucite which was mounted on a wooden frame, Fig. 1. The dimensions of the Lucite sheet were 36 ~ 36 in. The resistors were fastened to the Lucite sheet at mesh points by means of snaps. The mesh points were arranged in a square pattern, 30 ~ 30 in., spaced at intervals of 1½ in.

The snap fasteners permitted several resistors to be "stacked" in parallel. By adding additional resistors to the basic unit, the specific resistance on each side of the flood front could be varied.

The square network of resistors represented one of four symmetrical elements of a five-spot well pattern. The current input was analogous to an injection well and the current output was analogous to a production well.

The power supply was essentially a full wave transformer-rectifier system for converting alternating-current into direct-current. The DC voltage could be varied from 41.43 to 290 v in steps of 41.43 v by selecting the proper outlet jacks. The major components of the power supply were: a Triro power transformer, R 11-A; a dual 5Y3 vacuum tube; two gas filled OD–3 tubes; and a Triplett voltmeter, model 227–1, range 0 to 500 DC v.

The voltages at the mesh points were determined with a Keithley electrometer, model 210, No. 185, manufactured by Keithley Instruments, Cleveland, Ohio.
Multiphase Flow and Drilling-Fluid Filtrate Effects on the Onset of Production
Authors: Ladva H. K. J. , Tardy P. , Howard P. R. , Dussan V. E. B.
Published: December 2007

Formation damage from the drilling process must be overcome to initiate production in wells that are neither cased nor perforated. The drawdown to initiate production can be limited by low reservoir pressure, sanding potential, and water-coning concerns. In these cases, the required drawdown to initiate flow becomes important. Published results of laboratory experiments indicate that the flow initiation pressure (FIP) increases significantly when the permeability of the producing formation is below 50 millidarcies, and that it is lower for oil-based drilling fluids than for water-based fluids.1 This study presents possible explanations.

The dependence of FIP on formation permeability and drillingfluid type was evaluated both experimentally (with small cores) and theoretically. The results suggest that the relatively large FIP in low-permeability cores could be a consequence of conditions influencing multiphase fluid in the experiment (e.g., core length, or whether or not the experiments were run under constant flow or constant pressure-drop conditions). Under such circumstances, the onset of production in a well may not have the same dependence on formation permeability as does the laboratory-measured FIP. In addition, at least some of the drilling-fluid filtrate must be removed before any of the oil can be produced. When the filtrate is aqueous, capillary forces are present. The importance of these forces could explain why the FIP is higher for water-based than for oil-based drilling fluids. Both experimental and theoretical results are presented consistent with this explanation.
Investigation of H2S Migration in the Marjan Complex
Authors: Al-Eid Mohammad I. , Kokal Sunil L. , Carrigan William J. , Al-Dubaisi Jaffar M. , Halpern Henry I. , Al-Juraid Jamal I.
Published: December 2007

The Marjan complex is a large offshore oil field located in the Arabian Gulf and composed of four fields: Marjan 1, Marjan 2, Marjan 3, and Marjan 4. Currently, production in the complex is limited to the Khafji reservoir. For several years, it was known that the H2S concentration in the Khafji reservoir varied across the complex. A comprehensive study was initiated to map the concentration profile of H2S across the complex and to address the migration of H2S within it. This study included area-wide wellstream H2S measurement and geochemical fingerprinting of Marjan oil and gas. For the first time, the concentrations of H2S were mapped across the complex. The southern and southwestern wells show relatively high concentrations of H2S, and the northern wells show no (or negligible) amounts of H2S (less than 10 ppm). The migration of H2S into the northern part of the field has serious implications because the crude-handling facilities, or the gas/oil separation plant (GOSP), were designed for sweet crude processing. If migration is proven, the facilities in the northern part of the field must be upgraded to handle sour crude.

The results of this study indicate that there is a hot spot of high H2S located in the southwestern part of the complex. There is a significant H2S gradient across the Marjan complex, with H2S decreasing from the southwest to the northeast. H2S concentration profiles also indicate that there is an increase in H2S concentration with time in the hot spot. The data negate the possibility of H2S generation in the Khafji reservoir from either sulfate-reducing bacteria (SRB) or thermochemical sulfate reduction (TSR). Therefore, it is suggested that the H2S is migrating into the Khafji reservoir from somewhere else, probably from the Ratawi or other, deeper reservoirs.

The geochemical analyses show that the hydrocarbon composition is uniform across the complex, and there is no evidence for barriers to fluid flow within the Khafji reservoir. It is proposed that the lateral migration of H2S within the reservoir is arrested because of the presence of H2S-scavenging iron minerals. Two hypotheses are proposed for the migration of H2S into the Khafji reservoir from the Ratawi reservoir: (a) through interreservoir faults, or (b) through channeling leaks behind well casings. These two hypotheses are discussed in the paper.
Performance Drivers in Restimulation of Gas-Storage Wells
Authors: Mohaghegh Shahab , Mohamad Khalid , Popa Andrei , Ameri Sam , Wood Dan
Published: December 2007

To maintain or enhance deliverability of gas-storage wells in the Clinton sand in northeast Ohio, an annual restimulation program was established in the late 1960s. The program calls for as many as 20 hydraulic fractures and refractures per year. Several wells have been refractured three to four times, while there are still wells that have only been fractured once in the past 30 years.

As the program continues, many wells will be stimulated a second, third, or fourth time. This paper summarizes an attempt to carefully study the response of the Clinton sand to hydraulic fractures and to identify the performance drivers in each series of fracture jobs. Are the performance drivers the same for the later fractures (second, third, and fourth fracture jobs) as they were for the first ones, or do they change? This paper attempts to answer such questions.

Identification of major performance drivers becomes important when new jobs are to be designed. They not only play an important role in enhancing the response of the wells to new stimulation jobs, but they also may prove to be an important economic factor in the design of new stimulation procedures. If, for instance, it is concluded that an increase in proppant volume does not influence the stimulation outcome after the second refracture, then fewer resources can be used for proppant volume and can be directed toward parameters that are more influential.

This study employs a combined neural-network and fuzzy-logic tool to identify the performance drivers.
Mechanics of an Electric Submersible Pump Failure Mode
Authors: Powers Maston L.
Published: December 2007

The occurrence of electric submersible pump (ESP) failures caused by spinning diffusers is tolerably frequent in moderate-operating-cost circumstances. However, extremely high well-servicing expenses are associated with many ESP applications. Examples include deep wells, arctic locations, offshore wells that must be killed with high-density fluids, and seafloor completions. In these or other high-cost circumstances, early pump failures of any mode cannot be tolerated.

Longitudinal compressive force is imposed on the diffuser stack of ESPs during assembly to prevent diffuser rotation. If this is done improperly, the diffusers can spin because of torque transferred from the impellers, resulting in early pump failure. This paper analyzes the mechanics of the spinning-diffuser failure mode and demonstrates why some pumps with inadequate compressive force can pass common pump tests but fail in this mode. Equations are developed to calculate the restraining force as it changes under varying conditions and the minimum value required to prevent diffuser spinning. Testing procedures are proposed to emulate the effects of well conditions conducive to diffuser spinning, thereby detecting the defective pumps currently being missed. Practical examples are included that illustrate the utility of the concepts presented herein.
Drainage Anomalies in Gulf Coast Tertiary Sandstones
Authors: Hartman J.A. , Paynter D.D.
Published: December 2007

Drainage anomalies in Gulf Coast Tertiary sandstones are common phenomena. They can be present in reservoirs deposited in one geologic environment or several. Recognizing where these undrained areas occur leads to drilling of new wells or recompleting existing wells. Five examples of drainage anomalies in three offshore Louisiana fields are presented.

Introduction

Unanticipated drainage patterns, here called drainage anomalies, occur more frequently in Gulf Coast Tertiary sandstone reservoirs than commonly has been assumed. Although we may show on our maps and cross sections that all sandstone stringers in a given interval are in communication, this is often not correct. Sometimes potential areas where such anomalies may occur can be predicted during the primary development of a field. Usually these primary development of a field. Usually these drainage anomalies become apparent, however, only after considerable production has been obtained. Such anomalies are indicated by a detailed analysis of production and pressure data, by pulsed neutron production and pressure data, by pulsed neutron logs, and by logs in new wells drilled later in the life of the field.One of the best ways to ferret out areas where such anomalies may occur is by undertaking comprehensive subsurface engineering reviews that incorporate all geological, petrophysical, reservoir, and production data from the field. These reviews require a great deal of time to organize, analyze, and synthesize large amounts of engineering data; however, performed properly, they can be extremely rewarding. During these detailed studies, internal boundaries within a reservoir are often recognized. Many of these internal boundaries result because the sandstones were deposited in different depositional environments - e.g., channel sandstones cutting into fringe deposits. Drainage anomalies can occur however, even in sandstones deposited in on depositional environment. If these sandstones are delta fringe deposits, their vertical continuity is interrupted by shale layers, and in these cases the drainage anomalies are understood easily. Drainage anomalies, however, frequently occur in massive channel sandstones with no apparent shale layers These are more difficult to explain.

JPT

P. 1313
A Lumped-Parameter Model for Transient Two-Phase Gas-Liquid Flow in a Wellbore
Authors: Fairuzov Y. V. , Guevara J. Gonzalez , Barradas G. Lobato , Velázquez R. Camacho , Nucamendi F. Fuentes
Published: December 2007

In this study, a lumped-parameter model of transient two-phase gas/liquid flow in a wellbore is presented. The model is based on the assumption that the flow process is essentially one-dimensional so that an area's average properties can be represented as a function of one space variable and time. The wellbore is divided into a number of control volumes (nodes) that are connected by junctions (flow paths). A mass equation is formulated for each control volume, and an approximate momentum equation is used to calculate the flow rate at each junction. A numerical algorithm for coupling the wellbore model with a reservoir model is proposed. Calculations were carried out to determine the behavior of the wellbore flow during a pressure-buildup test. The results obtained from these calculations are compared to previously published theoretical results.
Matrix Treatment Employs New Acid System for Stimulation and Control of Fines Migration in Sandstone Formations
Authors: Thomas R.L. , Crowe C.W.
Published: December 2007

A matrix acidizing system employing fluoboric acid (HBF4) has been developed to stimulate problem sandstone formations. The fluoboric acid hydrolyzes to generate hydrofluoric acid (HF), thus achieving deeper live-acid penetration. Laboratory tests also show that spent fluoboric acid reacts with undissolved clay to reduce cation exchange capacity greatly and render the clay insensitive to incompatible fluids.

Introduction

Sandstone matrix acidizing long has been used as a means of improving production of oil. and gas by removing formation damage and increasing permeability of the zone immediately around the wellbore. Laboratory and field studies1–4 have demonstrated the effectiveness of this type of treatment. In spite of widespread use, however, many formations do not respond satisfactorily to conventional HCl/HF treatments. This normally is attributed to rapid spending of HF near the wellbore. Some wells initially show good stimulation but later experience an unusually rapid decline in production rate. Such production declines commonly are observed in wells producing from both consolidated and unconsolidated sands. The declines usually are attributed to plugging by migratory clays and other fines.

Formation plugging by migratory fines was demonstrated by Krueger et al.5 in both laboratory and field studies. Core test results revealed that high flow rates caused dislodgment of fines with resulting loss of permeability. Krueger also reported field studies in which the production decline rate was accelerated by flowing wells above an optimal rate.

As the production rate was increased, a corresponding increase in inorganic solids content of the produced oil also was observed. These observations strongly support the theory of formation damage from fines migration. Migratory fines apparently are released first by exposure to strong acid and later by mechanical forces resulting from the increased flow of produced fluids. Various treatments and production techniques6 have been devised in an effort to control or minimize this problem. Krueger et al.5 and Templeton et al.7 described treating techniques in which wells, following stimulation, were returned to production at a gradually increasing rate to minimize fines migration. Various clay stabilizing agents8,9 also have been applied in an effort to control movement of fines. Also, delayed acting acidizing systems7,10 have been developed to provide deeper live-acid penetration and, thus, remove damaging fines some distance from the wellbore.
Multivariate Optimization of Surfactant Systems for Tertiary Oil Recovery
Authors: Vinatieri James E. , Fleming Paul D.
Published: December 2007

A new method of optimization has been developed for tertiary oil recovery systems employing surfactants. This method simultaneously adjusts all composition variables in a manner which greatly reduces the total number of compositions which need to be investigated experimentally. This multivariate optimization technique has been applied to two petroleum sulfonate systems, one containing a pure hydrocarbon and the other containing a crude oil. In both cases, significant reductions of interfacial tensions were achieved relative to those obtained by conventional optimization with respect to salinity alone.

Surfactant systems for tertiary oil recovery commonly involve at least five components: oil, water, surfactant, cosurfactant, and electrolyte. The optimization of such systems is hindered by this large number of components and because interpolation of behavior is often difficult. Previously, such systems have been optimized by adjusting concentrations of individual components empirically. These empirical optimizations have indicated that surfactant systems which form three phases are preferred for oil recovery although they are not necessarily fully optimized. As stated by the Gibbs phase rule, a five-component, three-phase system has only two degrees of freedom at constant temperature and pressure. These two degrees of freedom can be identified mathematically by making use of chemical analysis of a three-phase sample. Thus, optimization of three-phase surfactant systems can be accomplished by adjusting only two variables, resulting in a dramatic reduction of time and effort required to optimize such systems.

For the systems studied, both the volume per unit mass of surfactant and the viscosity of the microemulsion phase are increased significantly even though the optimization was based on interfacial tension only. These bonuses should lead to improved sweep efficiency in the displacement process.
Compaction and Permeability of Oil-Shale Aggregates at High Temperatures
Authors: Trimmer D. , Heard H. C.
Published: December 2007

We have measured the change in bulk volume and permeability of an oil-shale aggregate subjected to high temperatures and pressures in a one-dimensional strain loading configuration. At stresses of 0.69 to 6.2 MPa and temperatures as high as 700°C, the 6-liter sample may compact by as much as one-third, and permeability may decrease by factors of 10 to 100. There is no simple relationship between strain or porosity and permeability. Attempts to analyze the data in terms of a Kozeny-type equation were unsuccessful.
Optimizing High-Temperature Kill Pills: The Åsgard Experience
Authors: Svoboda Charles
Published: December 2007

Historically, the survival rate for conventional, nondamaging polymer/carbonate kill pills under elevated temperatures was limited. Accordingly, a development program was instituted to develop a new high-temperature kill pill that would possess superb bridging characteristics on a high-permeability proppant while remaining thermally stable at temperatures exceeding 165°C (329°F).

This paper describes the development of a sodium formate kill pill geared specifically for the demanding Åsgard development in the Norwegian North Sea. The pill was engineered and successfully applied in a high-temperature application to seal a high-permeability (400 to 500 darcys) frac-pack sand in the Smørbukk field. In the field, the newly engineered formate-based pill proved to be thermally stable while providing sufficient leakoff control. Furthermore, the development reinforced the critical role of proper particle-size distribution (PSD) in minimizing fluid invasion.

With an emphasis on the PSD, this paper reviews the relative formation-damage potential testing procedure of the new formulation on simulated fracture packs. In the laboratory, the fluids demonstrated excellent thermal stability after long-term exposure to temperatures exceeding 150°C (300°F). The aging process was started simultaneously with two samples of each pill and concluded at the end of 16 and 72 hours, respectively. Leakoff tests were performed on 16/30 proppant at 165°C (329°F), resulting in minimal filtration. This paper also examines the unusually demanding conditions at Åsgard relative to other Norwegian fields and details the application and performance of the new kill pill in this hostile downhole environment.
Profiling Water Injection Wells by the Brine-Fresh Water Interface Method
Authors: Holbert Don R.
Published: December 2007

In order to attack the problem of channeling in water injection wells, it was felt necessary to have an accurate injection profiling means as a basic step. The means had to be capable of profiling injection wells that are permanently completed with cement-lined tubing which are heavily shot to produce highly irregular wellbores. The brine-fresh water interface method was chosen. The equipment and techniques developed for profiling by this method are described.

Experience has shown that the accuracy of the method is chiefly dependent upon the precision of the flow control systems and on allowing adequate time for stabilization of interface position. These operating limitations are discussed. The interface method can be broken down into the moving interface technique and the constant interface technique. The two techniques have been found to be complementary for obtaining injection profiles over a wide variety of conditions. For the constant interface technique, precision to .01 ft relative to other stations is common. This unusual degree of accuracy has led to the discovery of many instances where significant volumes of water are injected in very small vertical intervals. This indicates that channeling can be a problem even at moderate or low injection rates. In some cases the volumes of water injected have been so large and the formation intervals so small that flow through fractures rather than permeable streaks was considered probable.

It is possible that remedial procedures for fracture conditions could be quite different than remedial measures for permeable streak thief zones. The method accuracy and possible workover potential make interface profiling of practical significance for all types of water injection wells.

Introduction

In order to efficiently water flood a formation it is desirable that the injected water enter uniformly into all strata of the formation. If this is not the case, but a substantial portion of the injected water channels through fractures or excessively permeable zones, the oil production will be associated with excessive amounts of water. This obviously would adversely effect the economics of the operation.
An Improved Model for Predicting Separation Efficiency of a Rotary Gas Separator in ESP Systems
Authors: Harun A. F. , Prado M. G. , Shirazi S. A. , Doty D. R.
Published: December 2007

An improved model capable of predicting the separation efficiency of a rotary gas separator (RGS) in electric submersible pump (ESP) systems is presented. The model incorporates a new, two-phase, flow-inducer model capable of calculating the inducer head. The inducer head, generated by an RGS, has been identified as a key parameter that distinguishes between a separator's high-and low-efficiency regions. This information was previously determined empirically but can now be calculated. The new model more accurately predicts the maximum liquid rate at which an RGS should be installed. A comparison of the model's predictions with water/air and hydrocarbon/air experimental data indicates that the improved model performs better than earlier ones.
Automation System Case Study of Coalbed-Methane Development
Authors: Robertson Steve K. , Pool Mike , Farrens Michael J. , Butts Tammie J.
Published: December 2007

Can an independent producer fulfill a vision to develop and produce a coalbed methane (CBM) gas field that covers 200 square miles in a remote desert plateau in the western United States? This paper will answer that question as well as provide answers to other pertinent questions, such as:

What tools would be available to the operator to efficiently and safely produce the wells? Will the tools allow for future expansion and/or allow new technologies to be incorporated into the system in a cost-effective manner?

This case study will show how River Gas Corp. was able to successfully meet its needs with an automation system that was jointly developed with an engineering/manufacturing company. All phases of the project, from its inception in 1991 with a 13-well pilot project to a planned 600-well development, are discussed. Innovative solutions successfully answered the previous questions and allowed the system to evolve to meet the continuing changes in expansion and production needs.
An Analysis of Methods for Leasing the U.S. Outer Continental Shelf
Authors: Marsh G. Rogge
Published: December 2007

New U.S. laws require the use of many different offshore leasing methods. A computer program has been developed to analyze these alternatives. Economic characteristics are reviewed. Criteria are suggested for judging leasing systems. The most effective methods use cash bonus as the bid variable and a small fixed royalty or net profit share.

Introduction

The recently passed amendments to the Outer Continental Shelf Lands Act of 1953 enable the use of several different methods for leasing the U.S. offshore (Table 1). The U.S. Dept. of Interior, charged with the administration of the OCS, is required to use systems different from the current bonus-bid-plus-fixed-royalty method for at least 20%, but no more than 60%, of future leasing.Questions arise as one looks over this list. How will these alternative methods operate? How will they affect offshore operations? Are some systems better than others? The purpose of this paper is to try to answer these questions by (1) analyzing economic and operational effects of each leasing system, (2) examining the problems of selecting the "best" system, (3) proposing criteria for judging leasing systems, and (4) evaluating these systems.

EXXALT - An OCS Leasing Model

The tool used for this analysis is EXXALT, a Fortran IV program developed specifically to analyze alternative leasing methods. It is an extensively revised version of a program written at Cornell U.

Bidder's Attitude in Model

Any economic model of OCS operations must be concerned primarily with the formulation of the bid to win the tract. Because of this, the attitude of the bidder is a major concern. How will he act?The model assumes the bidder's view of the prospect is that it is either wholly contained oil one tract or unitized, it has some chance of being dry (though the basin is productive), and the range of possible reserve sizes is described by an input lognormal distribution.The bidder will make the largest possible bid to maximize his chance of winning the lease. This maximum bid results in a zero average net present value (ANPV) profit after discounting the expected net cash flow at the bidder's required discounted cash flow rate (DCFR).The bidder will ignore all other variables that may influence his bid, such as amount and nature of competition, "flinching" (a bidder's reluctance to bid above a certain monetary level), or other constraints imposed by a company's unique financial situation.

How Model Works

The flowchart in Fig. 1 shows how the program calculates a bid for a prospect. Offshore cost data and operational data (number of platforms and wells, amount of installed capacity, etc.) can be expressed as functions of field reserve size, water depth, and reservoir depth. These three parameters are the most significant.

JPT

P. 1262＾
Full-Scale Well-Model Tests of a New Chemical Plug System for Zone Isolation in Horizontal Wells
Authors: Gomez J. A. , Mamora D. D. , Lilledal L. O.
Published: December 2007

A new method for zone isolation in horizontal wells with chemical packers has been developed and tested with a 60-ft-long, full-scale horizontal-well apparatus. The method involves setting two chemical wellbore plugs in the horizontal section to straddle the problem zone, squeezing gel into the problem zone, and cleaning out the borehole before production. A crosslinked hydroxyethyl cellulose was used as the wellbore plug, while a monomer gel was used to shut off the problem zone. Tests confirmed the viability of the new zone-isolation method.
Petroleum For Our Future Progress
Authors: Gonzalez Richard J.
Published: December 2007

Since oil and gas supply two-thirds of the energy consumed in the United States, the availability of petroleum is a matter of vital concern for our economic progress and national security. A review of this subject is timely because of some recent predictions that the domestic industry cannot long sustain substantially increased production and that the United States will soon begin to run out of oil.

Fortunately, domestic crude oil production could be sustained at a rate more than 2,000,000 B/D above that of Oct., 1956, for a period of three years or more even with a substantial reduction in drilling. Drilling at current or higher levels will mean continuation of the past upward trend in domestic petroleum availability for the foreseeable future.

Recent estimates that the United States will only produce 150 to 200 billion bbl of oil will prove conservative because of improved producing techniques and additional discoveries in old and new provinces. The Dept. of Interior considers 300 billion bbl as the ultimate reserves of the United States to be a reasonable figure, and even that may seem conservative in another 20 years. As more oil is discovered, the estimate of ultimate production in the United States will continue to be pushed upward and the predicted date of running out of oil will be pushed further into the future.

The amount of oil to be found and produced in the United States will be affected by national policies on imports and on taxation of domestic production. A reasonable volume of imports will serve as all effective stimulus to efficiency in domestic operations but an undue volume of imports will have a damaging effect on our progress and security. Reasonable tax provisions on petroleum production are also essential to provide increasing quantities of oil for the future. The provisions applicable to petroleum production illustrate differential treatment that does not constitute a preferential tax advantage because it is related to the unusual risks in the search for oil. The existing rate of depletion comes close to measuring the capital value of oil in the ground while a lower rate would fall far short of recognizing the capital value that should be protected from taxation as ordinary income. National policies should be designed to encourage development of domestic resources in order that we may have sufficient petroleum for our future progress.
Lead Deposits in Dutch Natural Gas Systems
Authors: Hartog F. A. , Jonkers G. , Schmidt A. P. , Schuiling R. D.
Published: December 2007

During the production of natural gas from Dutch Rotliegend and Kupferschiefer sediments that are next to "conventional" carbonate and sulphate scales, lead deposits sometimes also form. These deposits, which vary in composition from galena (lead sulphide) to elemental (metallic) to lead and complex lead (hydr)oxides, may form a serious threat to operations because they tend to block production equipment or injection pumps and tubing. In some cases, radioactive lead (lead-210 with a half-life of 22.3 years) is incorporated into these compounds at levels greater than regulatory concern, which necessitates additional safety measures during operations and maintenance.

In sour gas wells, the deposition of galena can be explained by local supersaturation (caused by a sudden temperature or pressure drop) where bisulphide anions react with lead cations in the produced water, in which concentrations of up to 150 mg lead per liter brine have been detected. In the absence of hydrogen sulphide and even in "dry" gas wells, the deposition of metallic lead has been observed locally at rates of 10 g/D or more. An electrochemical mechanism is held responsible for lead deposition on carbon steel tubing: iron from the tube wall is oxidized by lead ions in solution, leading to corrosion of the wall and deposition of lead scales in thicknesses of 10 mm or more. Under unfavourable conditions or during maintenance operations, metallic lead is easily converted into secondary lead minerals.

Detailed knowledge on the geological origin, the transport pathways to surface facilities, and the mechanisms of lead scale formation might enable the future development of techniques that can prevent lead deposition.
Prediction of the Damping-Controlled Response of Offshore Structures to Random Wave Excitation
Authors: Vandiver J. Kim
Published: December 2007

A method is presented for predicting the damping-controlled response of a structure at a known natural frequency to random wave forces. The principal advantage of the proposed method over those in current use is that the explicit calculation of wave forces is not required in the analysis. This is accomplished by application of the principle of reciprocity: that the linear wave force spectrum for a particular vibration mode is proportional to the radiation (wave-making) damping of that mode. Several example calculations are presented including the prediction of the heave response of a tension-leg platform. The directional distribution of the wave spectrum is included in the analysis.
Specifying Lengths of Horizontal Wells in Fractured Reservoirs
Authors: Gale Julia F.W.
Published: December 2007

New methods have been developed to constrain optimal horizontal drilling distance in fractured reservoirs in which opening-mode fractures are dominant. Studies of opening-mode fractures in Austin Chalk outcrops and core reveal that open fractures are commonly clustered, with the distance between clusters ranging from approximately 1 m to more than 300 m, depending on the horizon in question. Aperture-size distributions follow power laws, and spacing-size distributions are negative logarithmic or log-normal. The aperture size at which fractures are open to fluids is variable and site-specific (0.14 to 11 mm). Scaling properties of fracture attributes were used to calculate fracture permeability and to constrain well-length fracture-permeability relationships. Fracture permeability depends on the scale of measurement; it has been determined at 9.2 darcies for 14 m of lower Austin Chalk core and 286 darcies for 300 m of upper Austin Chalk outcrop.
Champion East: Low-Cost Redevelopment of Shallow, Stacked, and Faulted Heavy-Oil Reservoirs
Authors: van Kessel Onno
Published: December 2007

The Champion East area offshore Brunei Darussalam consists of approximately 50 stacked, shallow, and intensely faulted heavy-oil reservoirs. These reservoirs have been under development since 1975 and have to date produced just 9% of the oil initially in place. Over the period 1998–2003, Brunei Shell Petroleum (BSP) is embarking on a major redevelopment with the aim of converting a further 30 million m3 of oil-in-place volume into commercial reserves.

An overview will be given of how new technology is adding value to the total redevelopment, supported by actual application results and learning points.

The primary development of Champion East is now nearing completion. The use of existing facilities and ultrashallow, long-reach horizontal wells—with innovative sand exclusion and down-hole intelligence—has achieved a 60% unit cost reduction over previous drilling campaigns in the area.

The only way to unlock another 5 to 15% of the oil-in-place volume is to start secondary recovery through water injection, in combination with the use of electric submersible pumps (ESPs).
Adapting Probabilistic Methods To Conform to Regulatory Guidelines
Authors: Acuña Herman G. , Harrell D.R.
Published: December 2007

Probabilistic methods have introduced inconsistent interpretations of how they should be applied while still complying with reserves certification guidelines. The objective of this paper is to present and discuss some pitfalls commonly encountered in the application of probabilistic methods to evaluate reserves. Several regulatory guidelines that should be followed during the generation of recoverable hydrocarbon distributions are discussed. An example also is given to understand the evolution of reserves categories as a function of probabilities.

Most of the conflicting reserves interpretations can be attributed to the constraints of regulatory bodies [e.g., the U.S. Securities and Exchange Commission (SEC)] and the current SPE/World Petroleum Congresses (WPC) reserves definitions in which reserves categories are expressed in terms of the probabilities of being achieved. For example, proved reserves are defined as those hydrocarbon volumes with at least a 90% probability of being equaled or exceeded (P90). Unfortunately, these definitions alone fall short as guidance on how to derive the distributions from which these percentiles will be calculated. This may lead to distributions that do not comply with the remaining guidelines. While a P90 can be calculated from a noncomplying distribution, proved reserves may not be assigned at this percentile level.