bluuebunny/crossref_metadata_2025_split huggingface dataset:
Pressure Falloff Analysis for Steam Injection Wells in a Low-Permeability Reservoir With Steam-Induced Vertical Fractures
Authors: Ambastha A. K. , Kumar M. 
Published: December 2007

ABSTRACT
This paper presents results of pressure falloff analyses for three cyclic steam injection wells in a low-permeability (&lt;1 md), heavy oil, reservoir with steam-induced vertical fractures. In one of the wells, a falloff test was also conducted after brine injection. The objectives of these tests were to estimate fracture and reservoir parameters and swept volume. The study also demonstrated the influence of wellbore thermal and fluid flow effects on pressure falloff test results in steam injection wells.
Results show that a good estimate of kxf2 can be obtained (where k is effective formation permeability and xf is fracture half-length). Approximate values of k and xf were also obtained. However, the estimate of swept volume using the pseudosteady-state analysis yielded unrealistically large swept-region width. This may be caused by the short steam injection time prior to conducting the falloff tests. Pressure falloff tests in all wells were significantly influenced by wellbore thermal and fluid effects which usually lasted for 10 hours or more. A new procedure is outlined to determine the period of wellbore effects.
Automatic Matching Type Curves for Pressure Transient Analysis
Authors: Duong A. N. , Foster G. A. 
Published: December 2007

ABSTRACT
The type curves using pressure/pressure-derivative ratio (PDR) was recently introduced so that the type-curve matching requires the movement of field data only in the horizontal direction. This improvement not only facilities the type-curve matching, but also increases the reliability of analysis results. However, the uniqueness of the results from a type-curve match is still the major concern.
This paper presents a new plotting technique for type curves and field data plot that will eliminate the movement of field data in both directions. The horizontal scales on both type curve and field data plots are fixed by the use of the time/pressure-derivative ratio (TDR) as a parameter in constructing the type curves and field data plot.
The paper concludes that using the proposed type curves with PDR and TDR as parameters will give the automatic alignments on both vertical and horizontal scales. Thus, the movement of data for type-curve matching is not needed. The wellbore storage constant, cD, can be read directly on the horizontal axis at PDR of 1.
The work of this study is limited to the type curves for wells in homogeneous radial systems with wellbore storage and skin.
Detecting Country Risks to Oil Companies in Lesser-Developed and Newly Industrialized Countries
Authors: Hallmark T. L. 
Published: December 2007

ABSTRACT
This paper examines the current status and function of oil industry-specific country risk assessment and identifies the existing level of threats to oil company investment in 15 lesser-developed and newly-industrialized countries. It is argued that relatively few countries are "off limits" to foreign oil companies and that risks to investment are determined more by host-country legislative or policy decisions than by serious macro-level or systemic disruptions. The 15 countries are then rated and ranked according to an analytical scheme utilizing 23 political, economic, legal and industry-related factors.
A New Biopolymer for High-Temperature Profile Control: Part II—Field Results
Authors: Sampath K. , Jones L. G. , Strom E. T. , Phelps C. H. , Chiou C. S. 
Published: December 2007

ABSTRACT
High temperature polymer formulations were successfully used to modify water injection profiles in the South East Bradley "A" Unit in Oklahoma. Injection profile logs show evidence of vertical sweep modification. Pressure fall-off tests show that areal sweep modification was also achieved. There was a strong oil production response to the polymer treatment. Incremental oil production during the first year following polymer injection was about 25,000 barrels, corresponding to about 0.8 barrels of incremental oil per pound of polymer injected. Production response is continuing.
Marine Construction In Cook Inlet
Authors: Nelson H.A. 
Published: December 2007

Marine construction in Cook Inlet, Alaska is probably more difficult and more hazardous than in any other area in the world. Marine construction in Cook Inlet for the petroleum industry began 1960 with the construction of a gas transmission line across Turnagain Arm to bring gas from the Swanson River Field to the city of Anchorage. (See orientation map) This project is considered by most to be the pioneer project of Cook Inlet marine construction. Though Turnagain is not the worst location with respect to weather, tide and current, the lack of experience with these elements made this a very difficult project. Methods of coping with the hostile environment of Cook Inlet have improved steadily since that time and oil companies and contractors have all benefited from studying the efforts of predecessors.

CONSTRUCTION TO DATE
At the present time, there are eleven offshore platforms installed in Cook Inlet with seventy-five miles of pipeline installed to service these structures. (See orientation map)
Generally, production is being delivered about evenly to the east side of the Inlet and to the west side of the Inlet.] Production from six platforms is going eastward and production from five platforms is going westward.
All platforms, except one, are of the four-leg type. One unique platform, the Monopod, is a single leg type developed especially for Cook Inlet. This platform has proven to be particularly successful in fabrication and construction.
CONSTRUCTION PLANNED FOR 1968
The smaller 1968 program probably represents a breathing spell for the oil companies as there has been a tremendous investment in Cook Inlet and returns on investment are not yet fully developed.

COOK INLET MARINE CONSTRUCTION PROBLEMS
Marine construction is hazardous in any locale as marine construction is particularly vulnerable to uncontrollable factors of weather, tide and current.
Drilling a Record Horizontal Well: A Case History
Authors: Brannin C. S. , Velser L. , Williams M. P. 
Published: December 2007

During early 1989, Maersk Oil & Gas A/S, as operator for Danish Underground Consortium, drilled the first horizontal well in the Tyra field, offshore Denmark. Prior experience acquired during horizontal drilling operations in the Dan field enabled Maersk to establish ambitious objectives for well TEB-1, including: displacement at total depth of 10,000 ft [3050 m], horizontal section of 3,000 ft [910 m], with maintenance of a 20 ft [6,1 m] vertical tolerance throughout, cementation, with rotation, of a 6 5/8-in [168,3mm] production liner across the horizontal completion interval.
To achieve these objectives economically, Maersk implemented a well profile with both long and medium-radius characteristics; steerable medium-radius angle-build drilling motors; thermally-stable synthetic diamond drill bits; and the most recent advances in liner hanger technology.
The unqualified success of drilling operations on well TEB-1 has confirmed the viability of precisely placed, high displacement, horizontal completion intervals as an economical alternative to more conventional field development strategies.
Kick Prevention, Detection, and Control: Planning and Training Guidelines for Drilling Deep High-Pressure Gas Wells
Authors: Hornung M. R. 
Published: December 2007

ABSTRACT
Conoco has developed generalized planning and training guidelines for well control on deep, high-pressure gas wells. These guidelines include a thorough review of gas behavior, causes of kicks, pressure indicators, and kick indicators as they are applied to high-pressure gas wells. The guidelines also emphasize the fundamentals associated with constant bottomhole pressure methods of well control. After the basic principles are reviewed, the characteristics of oil base mud are discussed. These characteristics are then related to all of the basic principles. Following this review, there is a practical example based on experiences Conoco had on a deep, high-pressure gas well drilled with oil base mud. Finally, there is the development of procedural and equipment requirements that are the result of having systematically addressed well control principles for deep, high-pressure gas wells.
Plotting Sonic Logs to Determine Formation Pore Pressures and Creating Overlays to Do So Worldwide
Authors: Weakley R. R. 
Published: December 2007

ABSTRACT
The determination of formation pore pressures from log derived properties is a highly used and accepted practice in the Gulf of Mexico. Such determinations in other parts of the U. S. and the world have generally been very difficult, if not impossible, in many instances. Failure to do so, in most cases, has led to extreme drilling difficulties or unsuccessful wells. Much of the time, high pressure shale sections have been misinterpreted as chemically sensitive formations requiring exotic mud chemistries and resulting in needless excessive expense.
We have developed a technique for the determination of formation pore pressures from sonic log trends which is universally applicable. This approach has been utilized in numerous locations around the world with great success. The process will be demonstrated in detail and several examples of results thus achieved from wells around the world will be presented.
In conjunction with this pore pressure determination process, a simple means of creating a pore pressure overlay to interpret the data will be demonstrated. This aids in speed of determinations and simplifies the analysis somewhat.
Before an estimation of anticipated pore pressures to be seen in a proposed drilling prospect can be made, determinations of actual pore pressures seen in offset wells is essential. These pore pressure determinations are therefore essential to the efficient an successful drilling of a well, and this technique enables one to make them.
Formation Damage Prevention During Drilling and Completion
Authors: Reed M. G. 
Published: December 2007

SUMMARY
The possibility of causing formation permeability damage exists during many operations throughout the life of a well. This paper deals with formation damage in only the earliest stages, i.e., during drilling and completion. Drilling fluid is the first non-indigenous fluid to contact the formation and thus, it provides the first opportunity for causing permeability damage. Other potentially damaging fluids that frequently contact the formation during drilling and completion are cements, perforating fluids, gravel packing fluids, and kill fluids.
Most drilling fluids are designed to de-flocculate clays and other fine particles in the wellbore, which is opposite to what is desirable in the formation rock. Therefore, filtrate invasion is potentially very damaging to the rock in the near-well area. Potentially damaging filtrates are also lost to the formation during well completions. Permeability damage frequently extends a few feet into the formation which makes it difficult to remedy. Therefore, damage prevention is very important.
Damage prevention is best accomplished by both minimizing filtrate invasion and the detrimental effects of invasion. While both are important, the latter is more practical because total elimination of filtrate invasion is virtually impossible. Water-based drilling and completion fluids can usually be made non-damaging by assuring that (1) they contain an adequate amount of salts, especially potassium salt, (2) they have a pH lower than about 9.5, (3) they do not contain materials that form precipitates on contact with formation water, (A) they contain a minimum amount of de-flocculants, and (5) completion fluids are clean. Laboratory flow tests using formation rock and reservoir fluids are useful for maximizing efficiency and effectiveness in the fluid design. Maximizing productivity of a damage susceptible well comes about only through a concerted effort to prevent formation damage during the life of the well, especially during drilling and completion.
The Design of Sucker Rod Pump Systems
Authors: Jennings James W. 
Published: December 2007

Abstract
The complete design of a sucker rod pumping system is an involved trial and error process. An "optimum" design requires that the engineer specify pump size and type; rod string size, taper, and material; surface unit type and size, gear box rating, beam rating, and stroke length; and prime mover type and size. The procedure requires that the engineer first assume an appropriate combination of pump, rod, unit, and prime mover and then perform calculations which lead to refining that initial assumption. This paper is intended to be a review of the several techniques commonly used to solve the problem. The author has taken the liberty to introduce several improvements to these techniques that have become apparent over the past several years.
As a minimum, the following information is required to start the design procedure:1
Fluid level Pump depth Pumping speed Length of stroke Pump plunger diameter Fluid specific gravity Tubing size and whether anchored or not Sucker rod size and design Unit geometry
The next step of the design procedure requires, as a minimum, the determination of the following operating characteristics of the design selection:
Plunger stroke Pump displacement Peak polished rod load Minimum polish rod load Peak Torque Polished rod horsepower Counterbalance effect
A High-Pressure Wellhead Lubricator
Authors: McKinney Howard E. 
Published: December 2007

Published in Petroleum Transactions, AIME, Volume 195, 1952, pages 261–264.

Abstract
A high-pressure wellhead lubricator has been developed to facilitate telemetering electrical measurements from subsurface reservoirs to the surface with the well under normal flowing conditions.
The field unit in use at the present time employs a 5/16-inch-diameter, single-conductor armored cable and is to be used in wells with surface pressures up to 5,000 psi. It has a pressure sealing element that maintains a continuous and absolute seal around the cable as it enters or leaves the tubing at speeds up to 175 feet per minute. A cable injecting device is used which obviates sinker bars or weight sections on the instrument.
The development of instruments for securing physical measurements in pressure wells has been confined in the past to those instruments which would operate on a wire line and record the necessary measurements in the downhole instrument itself, of those which would operate on an electric cable in a well with the surface pressure killed by the use of weighted fluids or by the use of tubing plugs. In one case the accuracy of the measurements is questionable, and in the other the range of application is very limited.
Considerable work has been done by other interests to provide effective means to accomplish the necessary telemetering. The U. S. Bureau of Mines developed a wellhead lubricator prior to 1947 which permitted a 5/16-inch-diameter single conductor cable to be lowered into a well with a surface pressure of approximately 500 psi. This unit was used successfully in a number of tests in Oklahoma. A company which tests wells has recently offered on a service basis a wellhead lubricator with a 3/16-inch-diameter cable that reportedly operates up to 2,500 psi surface pressures. Each of the above operates on a staging principle to effect a seal. In both of these units some leakage of well fluid occurs when the cable is moved.
In order to provide the maximum flexibility in its use, the following parameters were established for the design of our high-pressure wellhead lubricator:An absolute well fluid seal up to 5,000psi surface pressures.Means for raising and lowering the instrument at speeds of at least 100 feet per minute.Provision for the instrument to enter and leave the well without disturbing the well flow or the reservoir conditions.A cable large enough to provide suitable electrical characteristics and suitable mechanical properties.
Second Ripley Surfactant Flood Pilot Test
Authors: Reppert T. R. , Bragg J. R. , Wilkinson J. R. , Snow T. M. , Maer N. K. , Gale W. W. 
Published: December 2007

ABSTRACT
A second successful surfactant flood pilot test was conducted by Exxon on the Lewis Ripley lease in a watered-out portion of the Weiler sand, Loudon Field, Illinois. The salinity-tolerant, micellar/polymer process tested in this pilot incorporated several process modifications developed since a previous test was conducted in 1980. These changes included using a 25% smaller microemulsion bank size and addition of formaldehyde to injected fluids to inhibit bacterial degradation of biopolymer. The pilot was performed in a single, 0.71-acre [2873 m2], 5-spot operated to approximate a confined pattern. Extensive data on flood performance were obtained from a comprehensive pilot monitoring program, including use of fluid tracers, observation wells, and post-test cores.
Approximately 68% of the waterflood residual oil present in the test pattern was recovered. This actually exceeded the oil recovery achieved in the first pilot, despite using a smaller microemulsion bank. Improved mobility control and lower surfactant retention contributed to enhancing process performance. Formaldehyde was effectively transported and prevented bacterial degradation of biopolymer. It appears to be an effective biocide for use in subsequent surfactant flooding operations at Loudon. During the pilot, an inexpensive and efficient method was developed to separate produced oil-water-surfactant emulsions. While all test objectives were met, the effect of well spacing on oil recovery and chemical transport was not addressed.
Polymer Retention in Porous Media
Authors: Huh C. , Lange E. A. , Cannella W. J. 
Published: December 2007

Abstract
Retention of a polymer in reservoir rock is examined theoretically and experimentally. In the theoretical part, a pore-level description of mechanical entrapment of a polymer in a model porous medium is developed, which shows that the trapping rate is proportional to the flux of polymer, and decreases almost linearly with the amount of trapped polymer until the maximum retention is reached. The maximum retention increases with increasing polymer concentration, and also with increasing flow velocity. The dynamics of polymer trapping indicates that if a polymer has a good solvency in water, it has less tendency to be trapped; but if a polymer has a high intramolecular permeability, it will have a high tendency for trapping. Based on the pore-level considerations, a phenomenological polymer retention model is proposed that accounts for both the adsorption of polymer molecules on rock surfaces and the mechanical entrapment in pore matrices. An analytical solution for flow of a single-phase polymer solution in a core is obtained to interpret retention data from laboratory corefloods.
In the experimental part, the retention of xanthan biopolymers from semi-dilute solutions flowing in a sandstone core is measured as a function of polymer concentration, flow velocity, and permeability of rock. The proposed retention model is shown to adequately represent two characteristic features of typical polymer effluent profiles from corefloods, that is, the frontal delay and the gradual approach to feed concentration. Treating retention with adsorption alone generally fails to describe these features. The effects of dispersion and the commonly-encountered, high accumulation of polymer near the core face are also examined by analyzing the coreflood effluent data with a finite-difference numerical solution of the above linear flow problem.
Experimental Validation of a New Method for Optimizing Miscible Flooding of Stratified Reservoirs
Authors: Ingsøy P. , Skjaeveland S. M. 
Published: December 2007

Abstract
Miscible displacement experiments were conducted in a stratified model reservoirs that permitted visual observation of the flow processes. Concentrating on favorable mobility ratio displacements, the results are analyzed by a VE theory which includes gravity effects1,2. The results show that the front shape, and hence the recovery, of gravity stable displacements can be predicted by the theory. Further, rates for breakdown of gravity stabilization are predicted in agreement with experimental results. It is shown that channeling of the injection fluid into high permeability layers may be stabilized by viscous cross-flow, even during relatively high injection rates. Observation of unexpectedly large mixing zones are explained as viscous mixing caused by cross flow between layers.
A Method of Alternating Steam and Water Injection for Recovering Heavy Oils
Authors: Sufi A. H. 
Published: December 2007

Abstract
Various techniques have been suggested for injecting steam into heave oil reservoirs that offer limited injectivity into the formation. These include the use of any water-saturated stringers that may be present in the pay or the use of horizontal wells to heat the reservoir from the injector to the producer. An experimental study was conducted using a scaled physical model to study the scenario with a horizontal well. The model was an element of symmetry from a reservoir having no initial fluid mobility. A horizontal well was placed at the base of the model to heat the formation from a vertical injector to a vertical producer.
Results of injecting steam into the region heated by the horizontal well were disappointing due to low mass injection rates. It was possible to inject high mass rates using hot water as the injected fluid. This however, resulted in relatively low oil production rates. To obtain a balance between high mass injection rates and high oil production rates, a process of alternating steam and hot-water injection was developed. This allowed the reservoir to be heated as hot water was injected into the reservoir and oil to be produced by gravity drainage during steam injection. A number of alternating steam and hot water cycles were required before continuous steam injection at the maximum rate was possible. The initial heating time with the horizontal well was varied with minimal effect. Using the alternating process, an oil recovery of 76.4% was achieved.
Field Measurements of Remaining Oil Saturation
Authors: Causin E. , Rochon J. , Marzorati D. 
Published: December 2007

ABSTRACT
Some of the most promising techniques proposed for evaluating the remaining oil saturation (RÛS) of watered-out formations were tested in a few wells of three different fields Chuelles (Prance), Cortemaggiore (Italy) and a field in the Gulf of Guinea (Africa).
The work was carried out with the following main objectives :
– to identify a screening for selecting the best ROS measurement method(s) to be applied under different reservoir and/or well conditions; – to compare for the same well the results obtained applying different methods with various investigation depths; – to emphasize the importance of the in-situ ROS determination in heterogeneous reservoirs.
The techniques selected were:
– conventional carbon-oxygen logging; – pulsed neutron capture tool (log-inject-log); – single well tracer test; – interwell tracer test. The logging methods give results in good agreement in the high-porosity reservoirs conside red and can reveal a heterogeneous distribution of the oil saturation. The single well tracer test may be difficult to interpret when a significant heterogeneity and/or fluid drift occurs. In other cases, this tracer method can be very accurate. The interwell tracer test can give interesting results about flow behaviour in the reservoir, despite difficulties of test analysis. It can also measure an average ROS value at the end of a flooding process.
From this series of on-site experiments, we conclude that:
using more than one method improves the accuracy of in-situ ROS determinations; ROS measurements performed on one well are representative of the surrounding area; in-situ ROS measured at the end of the flooding process may be quite different from the residual oil saturation (Sor) measured in laboratory.