bluuebunny/crossref_metadata_2025_split huggingface dataset:
Extended-Reach Drilling from Platform Irene
Authors: Mueller M. D. , Quintana J. M. , Bunyak M. J. 
Published: December 2007

Abstract
Four wells have been completed on platform Irene at inclinations as high as 87 degrees. The most recent well, #A-16, was drilled to a total measured depth of 14387′, with a horizontal departure of 12740′ at a tree vertical depth of 4420′. Over 73% of the well path was at an inclination at which incremental drag forces exceeded the incremental inclined buoyed weight.
Major accomplishments for this will include:
-A 9-5/8" casing string was easily run to 8678′MD utilizing buoyancy assistance to minimize drag forces. Drag data proved that without buoyancy assistance the casing would not have made it past 7500′MD.
-Special drill string design minimized trip time while drilling by maximizing the depth at which pipe could be run without rotation. This same design technique enabled pushing open hole logs for over 5300′ to 14040′MD, while conventional drill pipe conveyed logging would barely have made it out of the 9-5/8" casing shoe.
-Almost 6000′ of 7" liner was rotated down the hole utilizing an innovative hydraulic releasing tool.
In addition to the above, this paper addresses well path and mud program design considerations, as well as problems encountered while drilling and completing the well.
P. 604
Gypsum Determination in Shallow West Texas Carbonates
Authors: Hedberg H. S. , May D. H. 
Published: December 2007

ABSTRACT
The younger Permian carbonates have been prolific producers over the years. The San Andresand Grayburg dolomites, which are productive in nearly all areas of west Texas, are ol particular note. Although traditional log analysis has been generally successful in ihese reservoirs, the presence ol gypsum in many has created difficulties. Gypsum tends to result in overly optimistic porosity calculations and also tends to restrict permeability by plugging the pore throats.
This paper exjfiains some ol the difficulties encountered when using traditional log analysis techniques in gypsiferous reservoirs and shows how the ELAN* log interjmetation program has been used to give superior results.
Field Experiences with Computer-Controlled Drilling
Authors: Brett J. F. , Warren T. M. , Wait D. E. 
Published: December 2007

ABSTRACT
This paper describes the mechanical, electrical, computer, and software systems of a prototype computer controlled drilling rig. The rig has operated under computer control for over three years on a project investigating optimized turbine control. In addition to describing the advantages and the basic computer control features of the rig, this paper presents the practical problems for computer controlled drilling and suggests possible solutions to these difficulties.
In the past, several attempts at full computer control of the drilling process have been made, but all have ultimately proven to be short lived. Recent advances in the power and reliability of sensors and computer control hardware, as well as reductions in their cost, have brought computerized rig control closer to reality. However, some important hurdles remain.
It is the authors' experience that most of the hurdles lie on the electrical and mechanical side of the system. Computer hardware and software capabilities have improved to the point that almost any function can be economically programmed. However, problems with sensor reliability and calibration, and actuation still exist. Each of these problem areas is discussed in this paper.
In summary, the purpose of this paper is: (1) to describe the use of a computer controlled rig, (2) to describe the problems the authors have experienced during three years of computer controlled drilling, (3) to present possible solutions to these problems, and (4) to discuss the future for field use of computer controlled drilling.
Vertical Permeability Determination From Pressure Buildup Tests in Partially Perforated Wellsa
Authors: Barnum R. S. , Frederick K. A. 
Published: December 2007

ABSTRACT
This paper describes a new analysis technique for determining vertical permeability from pressure buildup data in partially-perforated wells. The method applies when the vertical permeability is low enough that the Horner straight-line region characteristic of the perforated interval exists. A correlation chart is presented that relates the vertical permeability to the dimensionless pressure group (P* " Pi)/m, the percent completion, and a dimensionless time based on the flow duration, rock and fluid properties, and the thickness of the perforated interval. The variable m is the slope of the straight line corresponding to the perforated interval, p* is the extrapolation of this line to infinite shut-in time, and p,- is the initial reservoir pressure. Two simulated pressure buildup responses are presented and discussed to illustrate the technique.
Field Evaluation of New Treating Technique To Recover Permeability Damaged by Polymeric Materials
Authors: Dalrymple E. D. , McFatridge D. G. , Zeltman T. A. 
Published: December 2007

ABSTRACT
A recently developed treatment technique has significantly increased injectivity rates of injection wells which had been damaged by near-wellbore polymer blockage.
Polymer blockage can be caused by incompletely dissolved solid polymer, improperly inverted emulsion polymer, and/or deposition and adsorption of the polymer on the rock. Strong oxidizers such as hydrogen peroxide or sodium hypochlorite are typically used to clean up polymer deposits left after polymer injection; however, both of these chemicals present significant handling hazards. The treatment technique presented in this paper utilizes a solid oxidizer which releases a peroxide to dissolve the polymer deposits.
Field tests in Hockley County, TX, yielded injectivity rates more than double those recorded before treatment. The wells consisted of open-hole San Andres sections, at 4,850 to 5,050 ft (1,478.3 to 1,539.2 meters), with a bottom-hole temperature of 100°F (37.8°C). The polymer project was conducted from 1984 to 1986.
This paper discusses the solid oxidizer treatment technique and presents case histories and laboratory results.
Makeup Determination and External Testing of Internally Plastic-Coated Tubing Connections
Authors: Traweek J. B. , Nini C. J. , Gardenier D. , Hasha B. 
Published: December 2007

ABSTRACT
Tests were run on 2 3/8", 4.7 #/ft, J-55, 8-round, EUE, IPC tubing connections using data on position and connection strain to determine the proper torque to use in making up the connections with a Teflon thread compound. The tests were also used to determine if external testing Causes any connection or coating damage by further compressing the pin which is already in compression from being made-up.
Compositional Simulation of the Coyanosa Wolfcamp Field Gas Cycling Operation
Authors: Kim J. S. 
Published: December 2007

ABSTRACT
The Coyanosa Wolfcamp Field, located in Pecos County, Texas was discovered in September 1962. The reservoir rock is comprised of poorly sorted, coarse-grained heterogeneous conglomerates with thinly interbedding shaly limestones.
The dew point pressure of the Gas Unit reservoir ( representing about 80% of the Coyanosa Wolfcamp Field pore volume ) was 6,179 psia at a reservoir temperature of 175°F. The initial reservoir pressure was 6,700 psia. Mobil initiated a gas cycling operation in August 1964.
The condensate yield has declined steadily during the lean gas cycling operation. A compositional simulation study was undertaken to simulate complex mass transfer and composition changes. The study's objectives were to estimate the remaining condensate reserves and to determine an efficient depletion scheme including an optimum reservoir blowdown timing.
After matching the past 23 years of the product-ion history, the model was then used to predict future performance under the various operating scenarios.The sensitivity of liquid recovery to pressure, rate and degree of cycling was investigated. Depletion plans such as added compression, partial cycling and immediate blowdown were evaluated to devise an optimal operation plan.
New Stimulation Techniques Improve Canyon Sand Gas Production: A Case Study
Authors: Pferdehirt D. J. , Brown J. E. , Rucker L. R. 
Published: December 2007

ABSTRACT
It is an established fact that the Canyon Sand Formation in the Val Verde Basin must be fracture stimulated to exploit the reservoir's potential. However, in the past, the degree of stimulation required has been a judgement call at best. Due to recent results from an industry consortium dealing with conductivity, it became obvious that many past stimulation designs were inadequate. Changes in fracturing fluids, as well as proppant selection, concentration, and placement, have led to an improved design.
Past treatments were insufficient in fracture half-length and conductivity. These treatments have now been modified to double the fracture half-length, and to increase the conductivity six-fold. These design changes are necessary to overcome fluid damage and long-term conductivity deterioration. Computer simulated fracturing programs have been used to develop improved designs. When implemented in the field, these designs have proven to increase profitability through post-frac production results.
Although previously reported laboratory work has addressed the topic of in-situ fracture conductivity, these findings were not substantiated with actual production results. Therefore, a case study of twenty four wells located in Sutton County, Texas was performed to determine the actual effect of fracturing fluid type on well performance. A comparison of post-frac well production indicates that different fracturing fluids can dramatically effect a well's producibility. This case study supports the consortium's findings, that different fracturing fluid types create varying levels of permeability impairment.
Use of Stuck Pipe Statistics To Reduce the Occurrence of Stuck Pipe
Authors: Weakley R. R. 
Published: December 2007

ABSTRACT
The occurrence of stuck pipe can significantly increase the cost of drilling, decrease, if not eliminate, the success in reaching objectives, and negate attempts to retrieve valuable formation evaluation data. We have developed many tools and techniques in the oil field to solve problems such as stuck pipe after they occur, but the real key to savings and success is in the avoidance of the problem to begin with.
Approximately 600 wells were analyzed throughout the Gulf Coast and this survey included trouble free wells and those which had experienced differential and mechanical sticking as well. From this data, we are able to predict the environments which are likely to have a high risk of stuck pipe occurrence. Once knowing the risk factors, we are able to either design the well to avoid the high risk situations or to plan for it accordingly.
The results of this statistical analysis will be presented in a simple format which enables one to estimate the risk of occurrence for a given well. Use of the information for both well planning and the successful execution phase will be explained and demonstrated. Examples of the occurrence of problems when entering the high risk areas will also be illustrated. During the course of drilling some 100 wells, with attention to the guide lines to be presented, only eight incidences of stuck pipe were encountered.
Light Oil Recovery from Cyclic CO2 Injection: Influence of Gravity Segregation and Remaining Oil
Authors: Thomas J. , Berzins T. V. , Monger T. G. , Bassiouni Z. 
Published: December 2007

ABSTRACT
This paper presents results of an experimental and numerical investigation of the CO2 huff ‘n’ puff process for the enhanced recovery of light oil. The objective of the investigation was to increase our basic understanding of the process by examining the effects of a gas cap, gravity override, and remaining oil saturation on oil recovery.
In laboratory corefloods, the CO2 huff ‘n’ puff process was physically modelled using Berea sandstone with live and dead oil systems. Live oil was used in a vertical core at pressures above and below the bubble-point to study the influence of a gas cap. Stock tank oil was used in horizontal cores at immiscible conditions to study the effects of gravity segregation and remaining oil saturation. The cyclic process was also modelled using a three-dimensional fully-compositional reservoir simulator. Coreflood and numerical simulation results indicate that the presence of a gas cap, gravity segregation and higher remaining oil saturation improve process performance.
Characterization of Fracture Networks from Well Tests Using a New Analytical Solution
Authors: Corre B. 
Published: December 2007

ABSTRACT
This paper describes the first direct evaluation of various parameters of a fractured reservoir such as fracture compressibility, matrix block size and anisotropy of the fracture network. A new analytical solution is derived which reflects both double porosity and partial perforation effects. This technique is applied to an actual field to evaluate its applicability and reliability.
The field is dolomitic and intensely fractured as shown by well logs and cores. The fissure networks are partially injected with anhydrite. All the well tests studied here present double porosity behaviour which is sometimes reduced to a slight inflexion of the derivative curve.
Matrix block size and fracture compressibility are inferred from a double porosity matching. Several wells exhibit also an effect of partial perforation: in this case, the new technique developed in this paper makes it possible to calculate the vertical permeability of the fracture system.
The results show that:
The reservoir is composed of two distinct fracture networks. The typical block size of the most conductive network is in the order of ten to one hundred meters and that of the less permeable one is in the order of one meter. The vertical anisotropy kv/kh of the fracture networks varies from 0.01 to 0.22.depending on the matrix block size. An isopach of the fracture compressibility was produced for the whole field which reflects the presence of anhydrite.
All the observations mentioned above are supported by geological considerations.
Practical Transient Multilayer Test Design, Implementation, and Analysis of Gas Wells in the North Sea Southern Basin
Authors: Rapach J. M. , Jefferies R. , Guedroudj A. H. , Westaway P. J. 
Published: December 2007

ABSTRACT
Traditional pressure drawdown and build-up analysis of well tests in layered reservoirs has in many cases proven inadequate to describe layer parameters. Without a proper layer description which includes, pressure (Pe or Pr), permeability-thickness (KHl), Darcy skin (Sl), and non-Darcy skin (Dl), future well performance cannot be accurately described.
An innovative procedure was developed for gas wells in the North Sea Southern Basin to provide individual layer parameters in commingled, layered reservoir systems. The procedure incorporates pressure Transient Multi-layered Testing (TMLT) within the procedural framework of a Flow-After-Flow (FAF) test, utilising both wellbore pressure and layer rate transients. The TMLT technique has been successfully performed using a personal computer on 4 wells producing from the Rotliegendes sands in the Virgin condition 4V-Field wells, Vanguard 49/16 -Q03/08 and Vulcan 49/21-R06/06, and from the mature producing Victor field, wells 49/22-JD03/03Z and 49/22-JD05/05. Furthermore, the procedures and analysis for TMLT have been successfully executed in these wells despite layer boundaries, differential layer pressures, and problems/uncertainties inherent in spinner-determined flowrates.
Reservoir Variability and Modeling with Fractals
Authors: Crane S. D. , Tubman K. M. 
Published: December 2007

ABSTRACT
An important factor in the simulation of reservoir performance is the input reservoir parameters. Layers are often modeled with constant parameters (porosity, permeability, etc.) or with only minor variations. The failure to incorporate appropriate heterogeneity into reservoir performance predictions can be a significant problem.
This paper examines the variability in reservoir parameters as measured with wireline logs. Both vertical and horizontal well data are utilized for this purpose. The nature of the log variability in both a sandstone and a carbonate reservoir are evaluated using rescaled range (R/S) analysis in conjunction with power spectrum analysis, similar to the methodology of Hewett et al. The R/S analysis yields a fractal dimension that can be used to model the reservoir parameters. Both vertical and horizontal well log data can be characterized as fractional Gaussian noise of similar fractal dimension.
Fractal reservoir realizations are generated using Fourier transform techniques. This technique is straightforward and successfully maintains the desired spatial dependencies of the data. The fractal dimension is derived from the results of the statistical analysis. Some potential problems with this determination will be highlighted and discussed.
Examples of simulation results demonstrate improved reservoir performance predictions using the fractal realizations. Reservoir sweep efficiencies are altered and a different recovery performance is obtained relative to linearly interpolated realizations.
The Design, Development, and Field Testing of a Water-Cut Meter Based on a Microwave Technique
Authors: Yang Y. S. , Scott B. N. , Cregger B. B. 
Published: December 2007

Abstract
This paper will describe a new and unique instrument to accurately determine the water-cut of an oil-water emulsion. The basic principle of the measurement is based on a novel technique, commonly called oscillator load-pull, which detects the microwave characteristics of the emulsion. This measurement technique will be described simply and concisely. The design and development of the measurement pipe section and the necessary microwave oscillator source and control electronics will be discussed. Laboratory calibration data for the microwave water-cut meter will be presented. Installation of the instrument at a production facility will be described and field test results will be presented. Performance of the microwave water-cut meter will be compared to other water-in-crude determination methods including distillation and centrifugal separation.
An Inhibited Mud for Drilling Water-Sensitive Pay Zones
Authors: Hendrickson G.E. 
Published: December 2007

Abstract
Description of a water-base mud suitable for drilling, completing, of working over water-sensitive pay sands is given. This mud is inhibited by using salt, lime, and caustic soda so that its filtrate will not swell colloidal material with which it comes in contact within the pay sand. Conventional electric log can be run in this mud.

Introduction
A water-sensitive pay sand is one that has its permeability more or less destroyed when invaded by the filtrate from a conventional water-base mud. This destruction of permeability is not reparable under reservoir conditions by any known method. In Oklahoma most Pennsylvania sands, of less than 125 millidarcies, came under this classification. The amount of damage to the permeability caused by mud filtrate invasion seems to vary directly as the time the mud is on the pay zone and inversely as the permeability of the sand. Sands having permeabilities of 125 millidarcies or more are damaged to some extent but will usually clean up in a short time. Sands of approximately 60 millidarcies can usually be drilled and a drill stem test taken before much harm is done, but by the time pipe is set and the well completed, 25 to 50 per cent of the permeability will be lost. Sands of 30 millidarcies or less are, as a rule, blocked off by the time the well is completed and will not produce their full capacity on drill stem test.
The Cisco Sand field, near Frederick, Okla. was developed during 1951. The Cisco Sand is of Pennsylvanian age and is found at a depth of 2,800 feet. Its thickness varies from 10 to 25 feet and, from cores, the average permeability is 30 millidarcies. There are 35 wells in the field and none of them ever made more than a show on drill stem test, or more than a few barrels per day upon completion and before hydraulic-fracturing. After hydraulic-fracturing, these wells were completed for 200 to 300 b/d, natural flow. This is evidence that the conventional mud used in drilling almost completely blocked off the sand by the time the sand was drilled.
A semi-wildcat well drilled in the West Bradley field, near Lindsay, Okla., encountered the Hart Sand of Pennsylvania-age at about 8,000 feet. On drill stem test, this sand produced oil at the rate of 100 b/d. Based on this information and the thickness of the pay of 11 feet, several thousand barrels were set up as a reserve for this zone. The well was completed in a lower zone and the Hart Sand was not protected with cement. A year later, it was decided to test this sand and after squeezing, gamma ray, one oil squeeze and two hydraulic-fractures, no production could be obtained. This is a case where the mud had been on the sand for a long period of time. Examples like this are numerous.
Prediction of Separator Performance Under Changing Field Conditions
Authors: Choi M. S. 
Published: December 2007

Abstract
Over the life of a production system, the separator is expected to process a wide range of produced fluids. With break through from water flood and expanded gas lift circulation, the produced fluid water cut and gas-oil ratio is ever changing. In many instances, the separator fluid loading may exceed the original design capacity of the vessel. As a result, many operators find their separator no longer able to meet the required oil and water effluent standards, or experience high liquid carry-over in the gas. This paper describes a program developed to predict the effects that changing fluid conditions have on the performance of an existing three-phase separator. The procedure and computerized tools may be used for strategic planning when initiating pressure maintenance or artificial lift programs, or to optimize operating parameters of the vessel to yield the best effluent qualities.
Minifracture Analyses and Stimulation Treatment Results for CO2-Energized Fracturing Fluids in South Texas Gas Reservoirs
Authors: Juranek T. A. , Llewellyn M. T. , Drescher G. P. , Tan H. C. , McGowen J. M. 
Published: December 2007

Abstract
CO2-energized fluids can offer advantages over conventional fracturing fluids. However, quality control and design optimization become more difficult with gasified fluids. Minifracture analysis, a valuable tool in optimizing conventional fracturing fluid designs, has not been previously extended to energized fluids.
Minifracture treatments with fluids containing 25% to 70% CO2 were performed on three case wells in Montgomery and Webb counties in south Texas. Data and results from these treatments are detailed in this paper. Significant thermal and compressibility effects were observed during the minifracture pressure declines. An analytical technique which corrected for these effects was used to estimate fluid leakoff based on pressure decline behavior. Improved stimulation results were obtained by redesigning the treatments based on the calculated leakoffs.
An Approach to Reservoir Management
Authors: Wiggins M. L. , Startzman R. A. 
Published: December 2007

ABSTRACT
Many petroleum reservoirs are not developed and produced properly. This failure can be the result of poor reservoir operations management. An understanding of reservoir management and its elements is needed to effectively exploit petroleum reservoirs. This paper defines reservoir management and proposes a comprehensive, integrated approach to the management of reservoir operations.
The paper does not address the many technical details of reservoir management, nor does it give detailed recommendations for particular operations. It presents a method and approach to making these decisions for any reservoir. Its purpose is to communicate the importance of reservoir management and to present an approach for the development of a reservoir management plan.