bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Effect of Drilling Fluid Base-Oil Properties on Occupational Hygiene and the Marine Environment
Authors: Saasen A. , Berntsen M. , Løklingholm G. , Igeltjørn H. , Åsnes K. 
Published: December 2007

Summary
Drilling operations can require the use of oil-based drilling fluids (OBM). These fluids are formulated as an emulsion consisting of water emulsified into a continuous oil phase. During the past decade, the North Sea drilling industry has moved from using diesel oil to low-toxic base oils in OBM. Further development of low-toxic base oils has continued on the Norwegian sector of the North Sea and has resulted in the use of nonaromatic base oils.
This paper describes the results from a field test in which the introduction of nonaromatic base oils reduced the hydrocarbon content by more than 50% in head space level in the shale shaker area, compared to the use of low-toxic base oils. In this test, two wells were drilled in which the hydrocarbon vapor and mist were collected at the same locations in the shaker area. The first well was drilled with a more traditional low-toxic, mineral-oil-based drilling fluid. The second well was drilled in a comparable formation with a drilling fluid based on the nonaromatic base oil. The paper also describes how skin irritation is reduced when using the nonaromatic base oils, compared to the use of previous base oils and synthetic base oils.
The paper discusses biodegradability and toxicity of different base oils. Ecotoxicological test results indicate that use of the nonaromatic base oils may result in less environmental impact, compared to the use of other mineral oils or the synthetic oils used in Norway, if an accidental discharge occurs.
Finally, the paper discusses dermal irritation effects from the different drilling fluids. It is shown that use of the nonaromatic base oil reduces the skin irritation index compared to use of other oil or synthetic base oils.
Enhanced Oil Production Owing to Sand Flow in Conventional and Heavy-Oil Reservoirs
Authors: Wang Yarlong , Chen Carl C. 
Published: December 2007

Summary
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

Abstract
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

Summary
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

SummaryFormation 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

Summary
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

Summary
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

Summary
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