bluuebunny/crossref_metadata_2025_split huggingface dataset:
Quantitative Measurement of Flow Heterogeneity in Laboratory Core Samples and Its Effect on Fluid Flow Characteristics
Authors: Johnson Carl E. , Sweeney S.A. 
Published: December 2007

Abstract
Flow heterogeneity in laboratory core samples can significantly influence the experimental measurement of reservoir rock flow and displacement characteristics useful in reservoir engineering calculations and in evaluating new oil recovery methods. This variable in laboratory measurements deserves more attention than it usually receives and, although the more extreme causes of flow heterogeneity in core samples such as cracks, voids and obstructions are often easy to recognize, there is need for a more precise method for measuring this kind of heterogeneity.
The method developed and presented in this paper treats the presented in this paper treats the core sample as if it were composed of 50 parallel flow paths. The fluid conductivities of the 50 flow paths are deduced from the results of a simple equal viscosity, equal density miscible displacement experiment performed on the sample, and the performed on the sample, and the pattern of distribution of these pattern of distribution of these conductivities provides a quantitative measure of the degree and character of the flow path heterogeneity present. The paper presents equations for calculating flow path heterogeneity patterns and several examples showing patterns and several examples showing how these measurements can be useful in laboratory experimentation.

Introduction
There is considerable evidence that flow heterogeneity is an important variable in the laboratory measurement of the flow and displacement properties of oil field core samples, and that it may significantly affect the results of such measurements. In spite of the evidence, little attention has been paid to the quantitative measurement of paid to the quantitative measurement of this variable. It is, however, usually agreed that uniform, fairly homogeneous core samples are required if the experimental data obtained is to be useful in reservoir engineering calculations.
Pollution Control in the Alberta Oil and Gas Industry
Authors: Bohme V.E. , DeSourcy G.J. 
Published: December 2007

Abstract
Alberta's Energy Resources Conservation Board was given statutory responsibility for pollution control in the oil and gas industry pollution control in the oil and gas industry in 1970. This paper describes the history and objectives of pollution control in the industry and provides detailed descriptions of the more important pollution control regulations applicable to drilling, producing and gas processing operations.
A brief summary of the size of the industry is given to show its importance in the economy and environment of Alberta. The province's natural environment and its population distribution are briefly population distribution are briefly described to indicate the manner in which drilling and production activities have affected Alberta and its people.
The Board's role in pollution control prior to 1970 is mentioned to show how prior to 1970 is mentioned to show how early pollution control activities developed largely from the application of resource conservation principles.
To allow the industry to work under a single agency as much as possible, the pollution control activities of most pollution control activities of most government departments affecting drilling and producing were transferred to the Board in 1970. The method of integrating the pollution control activities of the departments into the Board is outlined and the continuing relationship between these departments and the Board and the industry is explained.
The Board's objectives regarding pollution control in drilling, producing, pollution control in drilling, producing, gas processing, oil sands processing and pipe line operations are described. A pipe line operations are described. A summary of pollution control regulations indicates the application of the objectives to operations and equipment in the industry.
Schematic figures indicate detailed pollution control requirements applicable pollution control requirements applicable to drilling, producing wells, batteries and gas processing plants.

Introduction
The Province of Alberta is the second most westerly Province in Canada. It is bordered on the south-west by the Rocky Mountains and its physiography ranges from flat prairie in the south and east to heavy forest and rolling bush land in the north and west. The State of Montana lies directly south of Alberta.
Protection of an Aquifer - A Case History
Authors: Owens Willard G. 
Published: December 2007

At the request of a Colorado Ground Water Management District Board of Directors, we studied the bedrock aquifers within and in the immediate vicinity of the District. The purpose of the study was to develop bases for the effective and meaningful rules, regulations, and conservation measures to be adopted by the District. Our study included the compilation of data on the deep aquifers to develop an understanding of the suballuvium geologic formations so existing and future water rights can be protected while allowing optimum development protected while allowing optimum development of ground water resources from the deeper aquifers.
The tabulation of municipal, commercial and other significant water supply wells completed in the bedrock aquifers was included in an engineering geologic report.
BEDROCK AQUIFERS
The results of our hydrogeologic study show that there are four significant bedrock aquifers within the District. These are:
Dawson-Arapahoe sands
Laramie sands
Fox Hills sands
Pierre transition zone sands
These bedrock aquifers occur at or near the surface within the District as shown on Plates I and II. These aquifers are made up of sands and sandstones which are interlayered with shale. The dip is toward the south-southeast into the Denver Basin. Plates III, III-A and IV are geologic cross-sections which show how these aquifers occur at depth. These cross-sections also show the correlation of the sands over considerable distances and the manner in which the sands are separated from each other by relatively impermeable shale.
Dawson-Arapahoe Sands
This aquifer occurs in the southwest one-third of the District, as shown on Plates I and II. This aquifer is defined Plates I and II. This aquifer is defined as sands and sandstone, ranging in grain size from fine to very coarse, which overlie the predominantly shale section of the Laramie formation. The Dawson-Arapahoe aquifer occurs from the surface to a depth of approximately 800 feet in the immediate vicinity of Strasburg and approximately 1,200 ft. at the southwest corner of the District boundaries.
The Thermo Tube, A Natural Convection Heat Transfer Device for Stabilization of Arctic Soils in Oil Producing Regions
Authors: Babb Albert L. , Chow David M. , Garlid Kermit L. , Popovich Robert P. , Woodruff Eugene M. 
Published: December 2007

Abstract
A brief mathematical analysis of the heat transfer device is given followed by an experimental evaluation of Thermo Tubes of different geometrical configuration. The capability of these natural convection heat transfer devices to store "cold" in various media and in appropriate structural elements is explored. Mathematical models are described which couple soil enthalpy fluctuations with those of the cold storage media, and include temperature constraints imposed by the ambient air and the soil surface temperatures. These analyses have been applied to the design of specific structures for pipelines and oil wells in which rigid thermal pipelines and oil wells in which rigid thermal and structural requirements need to be maintained year-round, particularly in warm permafrost regions such as Glennallen, Alaska. permafrost regions such as Glennallen, Alaska.

Introduction
This paper describes a natural convection heat transfer device originally devised by Balch, and subsequently modified and applied to provide stabilization of structures in permafrost regions of the Arctic. permafrost regions of the Arctic. A schematic diagram of the Thermo Tube is given in Figure 1 and structural details of the 3-inch and 8-inch tubes are given in Figure 2. In the lower half, heat is absorbed from the surrounding medium which warms the working fluid The warmed fluid rises to the upper heat rejection surface through an inner tube and gives up its heat by conduction and natural convection by means of finned surfaces in the cooler medium. The total thermal capacity of a given tube depends not only on the geometrical configuration but also on the working fluid, the temperature difference between the cold air and the warmer region to be cooled, and the thermal properties of the heat rejection and the heat absorption media. In practice, the ratio of heat rejection area to heat absorption area is about 3:1.
Oil Mud Logging On The Gulf Coast
Authors: Robinson H.C. 
Published: December 2007

Abstract
Effective logging programs are available for wells drilled with non-conductive oil muds. The basic log in such a program is the simultaneously recorded Gamma Ray-Induction Survey. This log provides the primary means for correlation, depth control, and for determination of resistivity values for qualitative and quantitative interpretation.
The Sonic Log, used in conjunction with the resistivity values from the Induction Log, serves as an excellent detector of hydrocarbon-bearing zones.
Determination of porosity is best accomplished with the Formation Density Log. In addition to supplying reliable values of effective porosity, this is the most accurate logging means of determining the lithology of the sand-shale sequences, found in this area.
The use of Induction, Sonic, and Formation Density Logs provides data for complete interpretation of water saturation, effective porosity, and shale content.
Other wireline tools, such as Neutron, Dipmeter, Sidewall Coring, and Wireline Formation Testing, are effective in oil muds.
A Study of Water Coning in the Kaybob South Beaverhill Lake Field
Authors: Graue D.J. , Filgate R.A. 
Published: December 2007

Abstract
Water coning in the Kaybob South Beaverhill Lake Gas Field in West Central Alberta was investigated because production in nearby fields demonstrated that it could be a serious operational problem. The formation water is very corrosive and prohibitively expensive to produce. produce. The water coning phenomenon was studied with the help of a numerical calculation model. The data used in the calculations consisted of fluid and rock data, core analyses, and flow test results. Both vertical and radial variations in permeabilities were included as well as an approximation of non-Darcy flow.
Two field cases where water breakthrough had occurred were history matched with the model. Based on model calculations for 20 other wells, the critical flow rates of 38 producers were estimated.
The results of the model calculations showed that:
(1) critical height is the dominant factor in determining critical flow rate;
(2) the ratio of horizontal to vertical permeability is next in importance;
(3) non-Darcy flow can be approximated in a Darcy flow model; and
(4) non-Darcy flow did not have a strong effect on critical flow rates, at least on wells with critical heights of 50 ft or more.

Introduction
Kaybob South Beaverhill Lake Gas Unit 3, shown in Fig. 1, was developed to meet a required producing capacity of 490 MMcf/D of sour, producing capacity of 490 MMcf/D of sour, condensate gas and a required injection capacity of 260 MMcf/D of dry, recycled gas. Unit 3 contains about 2 Tscf of gas at 4,350 psig and at a depth of about 11,000 ft. About 30 billion bbl of water containing over 200,000 ppm salts underlie the field.
The formation water is extremely corrosive, and the costs of producing it are prohibitive. In nearby Pine Creek field, 10 of the 11 gas wells have been shut in due to water production, and in Kaybob South Beaverhill Lake Units 1 and 2, 11 of the 46 producing wells have begun producing water. It was necessary to replace producing water. It was necessary to replace one gathering-system trunk line in Unit 1 due to corrosion after less than 1 1/2 years on production.
The costs to drill and tie in a new well are between $400,000 and $500,000. Therefore, economics strongly favor producing the wells at low enough rates to prevent water production. In addition, the Alberta Oil and Gas Conservation Board requires operators of gas fields to investigate potential water coning problems and their effect on ultimate gas problems and their effect on ultimate gas recovery.
Fast Water-Coning Evaluation Method
Authors: Bournazel Claude , Jeanson Bernard 
Published: December 2007

Abstract
Many approximate methods have been published for making fast evaluations of published for making fast evaluations of reservoir behavior when water coning is involved.
Based on theoretical or experimental research, these methods usually provide a fairly close approximation of the critical flow rate and the breakthrough time under restricted geometric and drive conditions.
However, when economic necessities make production above the critical flow rate production above the critical flow rate inevitable, the WOR increase versus time or oil production must be evaluated. Heretofore this evaluation has required the use of complicated and costly mathematical models.
This paper proposes a new method combining experimental correlations using dimensionless numbers with a simplified analytical approach based on the assumption that the front shape behaves like a current line, in an equivalent model of different shape.
This method can be numerically processed quickly and easily. It gives a sufficient approximation of both the critical flow rate and the breakthrough time as well as of the WOR increase, the pressure drop, the productivity index and the minimum flow value below which it would be necessary to decrease the flow rate for excluding water production.
The process can be applied to any thick homogeneous reservoir which is horizontally fed.
Conversely, the method can be used for approximately determining the optimum completion and withdrawal rate.
The results obtained using this method have been compared with those from numerous diphasic flow experiments using different-sized physical models. The initial conditions and the fluid characteristics were varied to a large degree during these experiments.
Although the calculations do not take into account the capillary forces existing in the model, there is satisfactory agreement between the different results: agreement which is expected to be sufficient for making a fast prediction and especially for choosing the prediction and especially for choosing the penetration depth. penetration depth. An example is given of how this method is applied to a topical problem. This is followed by a discussion of the influence on water-coning behavior of the different parameters that usually characterize displacement.
Acid Stimulation of Openhole Horizontal Section Behind Prepack Screen Using Coiled Tubing and New Isolation Method
Authors: Koshak W. E. (Skip) , Attah Mike 
Published: December 2007

Abstract
Several techniques are available to remove residual drilling fluid and filter cake from the openhole section behind prepacked screens. This paper describes the use of a new method that isolates the screen and circulates the acid from the screen "toe" back to the "heel" by means of a sliding sleeve. Coiled tubing is used to perform the stimulation operation and manipulate the sliding sleeve.
New Tooling & Techniques Lead to Success of CT Deployed Thru-Tubing Gravel Packs
Authors: Picou R. A. , Hebert L. 
Published: December 2007

Abstract
Due to the development of new tooling and the use of sound engineering coil tubing deployed thru-tubing gravel packs have become an economical and efficient means for the control of sand production.
The authors of this paper have been involved with over forty such jobs in the past two years. The goal of this paper will be to convey the experiences gained in both newly developed component technologies and applications engineering that has been responsible for their overall success.
Project Copernicus – 2nd Generation CT/SHD Rig
Authors: Burge Phil 
Published: December 2007

Abstract
The modern era of drilling using coiled tubing began in the early 1990's and was made possible by the development of enabling technologies such as slim-hoie drilling tools, improvements in tubing metallurgy and horizontal drilling techniques. The industry has recognised that coiled tubing drilling is most applicable for underbalanced drilling, re-entry drilling and through tubing re-entry drilling. Most coiled tubing drilling jobs have been completed using conventional or slightly modified coiled tubing units. A number of hybrid units have been built that incorporate conventional coiled tubing technology with conventional hydraulic jack systems for jointed pipe handling. At the same time as interest in coiled tubing drilling has grown, the interest in slim-hole drilling has waned as the industry recognised that although there was a need for fit for purpose slim-hole drilling units, the capital to build the units was not available. This paper describes a unique rig concept that has been designed specifically for coiled tubing drilling and slim-hoie drilling applications using jointed pipe.
Maximum Set Down Weight and Overpull in Coiled Tubing Simulations
Authors: Suryanarayana P. V. R. 
Published: December 2007

Abstract
Maximum Set-Down weight and Maximum Overpull are important limiting parameters in the design of Coiled Tubing (CT) operations. In the past, these have been calculated using time-consuming iterative approaches that may need 20 or more iterations using a CT forces simulator. We describe here a more efficient approach that allows the computation of these parameters directly, with a very low computational overhead. The procedure is based on the behavior of partial derivatives that describe axial force-transmission along the CT. The procedure and its mathematical basis are discussed, and an illustrative example is presented. Besides being faster, this procedure also provides physical insight into the force transmission in CT. It can also be used to predict the lock-up depth and maximum reach in CT operations.
Laboratory Development and Field Application of a Novel Water-Based Drill-In Fluid for Geopressured Horizontal Wells
Authors: Dobson J. W. , Harrison J. C. , Hale A. H. , Lau H. C. , Bernardi L. A. , Kielty J. M. , Albrecht M. S. , Bruner S. D. 
Published: December 2007

Abstract
Research has identified a novel water-based drill-in fluid for drilling and completing geopressured horizontal wells. This fluid has a unique combination of properties which make it especially suitable for geopressured applications. They include the use of calcium and/or zinc bromide as a base brine, minimal concentration of calcium carbonate as bridging material, low plastic viscosity, tight fluid loss control, good filter cake properties, and excellent return permeability. This drill-in fluid has been used successfully to drill a 1,200 foot production interval, 4.75 inch diameter wellbore in the Gulf of Mexico with a system weight of 13.2 lbm/gal, bottom hole temperature of 185° F., and a 1400 to 1700 psi overbalance. The system functioned very well in both the drilling and completion operations. Fluid rheology was easily maintainable and the hole conditions were excellent without torque or drag problems. Initial production data suggests that the well is producing at expected rates with low drawdown pressure.
Production Enhancement Through Aggressive Flowback Procedures in the Codell Formation
Authors: Anderson A.J. , Ashton P.J.N. , Lang J. , Samuelson M.L. 
Published: December 2007

Abstract
Proppant flowback following fracture stimulation treatments continues to be a major concern in many wells around the world. The current trend towards more tip screen out (TSO) and reverse screenout designs has increased the need for better control of proppant flowback under increasingly severe drag force conditions.
Recent studies in the Codell formation have indicated a correlation between load water and polymer recovery on fracture cleanup and subsequent gas production. This paper describes a subsequent twenty-five well study of the specific effects of combining forced closure/reverse gravel packs along with varying flowback rates and choke schedules on load water recovery and normalized gas and condensate production. One of the key issues addressed is the use of aggressive flowback schedules while maintaining proppant flowback control.

Introduction - Codell Description
The Codell is a tight shaly sandstone that produces varying amount of gas and condensate in the D-J Basin of northeastern Colorado (Fig. 1). It is a retrograde condensate reservoir producing below the bubble point. Water production in the subject area is very small, usually 0 to 2 bpd. Formation characteristics are listed in Table 1. Some parts of the field are highly naturally fractured which can cause early screenouts of fracture treatments, but these natural fractures can also aid in production. Directly above the Codell is the Ft. Hayes member of the Niobrara formation, which is a clean limestone. The Ft. Hayes is also very brittle and could be naturally fractured in certain geographic areas. As most of the screenouts have been localized in specific geographic areas, it is believed that the fracture can grow up into the Ft. Hayes resulting in excessive fluid loss and causing an early screenout. A good indication of natural fractures is when a Density-Neutron log shows gas in the Ft. Hayes. Unfortunately very few of these logs have been performed.

Field Study - Fracture Design
Due to the low permeability, the Codell must be fracture stimulated to be productive. Height growth while fracturing the Codell is believed to be predominately downward approximately 300 feet into the nonproductive Carlisle shale. Diversion techniques have been used on many of the wells to try to control the downward growth of the fracture. Fracture treatment designs have ranged from 175,000 to 250,000 total lb. of proppant added, with ramp schedules ranging from 2 ppa to 10 ppa, with an average concentration of 3.4 ppa.
Several papers have been written about optimizing the fracture design in the Codell formation. A statistical study performed by Donovan indicated that proppant volume did not significantly affect the three year cumulative BOE, but that the net pay was the most important factor. Parker et. al. determined that inadequate fracture length and conductivity were the main problems to unsuccessful treatments.
P. 525
Time Lapse Resistivity and Water-Content Changes in Shale
Authors: Morriss S. L. , Chenevert M. E. , Javalagi M. I. 
Published: December 2007

Abstract
An experimental study was made of the change in resistivity as a function of time and distance in a shale sample exposed to a liquid at one end. Two distinct shales were used in the study, Pierre and Wellington. The liquids used included KCl and NaCl solutions as well as deionized water. Resistivity was measured at three distances from the exposed end of the core samples using a six-electrode configuration. Simultaneous measurements of the swelling of the sample were used to calculate water content changes at the same three positions. The mineralogical composition of the shales was determined by x-ray diffraction analysis, resulting in a reasonably good estimate of the amount and type of clay present. Atomic absorption measurements were made on selected samples and the brine to which they were exposed in order to quantify ion movement. The results of this study give some insight into the changes in those properties of a swelling shale which influence resistivity, neutron, and density logs, and the time scale involved in the propagation of those changes away from the wellbore into the formation. While resistivity exhibits the largest relative change of the properties measured, it appears that the depth of investigation of a logging tool must be quite small for the changes to be detectable, for example.