bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Liquid-Freon Permeameter
Authors: Hurd B.G. 
Published: December 2007

HURD, B.G., SOCONY MOBIL OIL CO., INC., DALLAS, TEX.

Abstract
A liquid-Freon permeameter suitable for making routine permeability determinations on small plug samples is described. The instrument is characterized by simplicity of design and ease of operation, and can be assembled inexpensively from stock items of laboratory equipment. It combines the unique advantages of both liquid and gas permeameters while eliminating many undesirable features of both general classes of instruments. Precision and accuracy of the specific Freon permeability measurements compare favorably with results of conventional liquid and gas permeameters.

Introduction
The liquid-Freon permeameter described in this paper was designed and built for special investigations of the properties of petroleum reservoir rocks. However, its unique advantages over conventional gas and liquid permeameters make it eminently suitable for routine use in the core analysis of small plug samples. In general, gas permeameters are very popular because of their simplicity of design and ease of operation. However, apparent gas permeabilities are normally higher than true specific permeabilities unless special corrections for gas-slippage are applied. Since these corrections require two or more measurements at different internal gas pressures, much of the time advantage of the specific gas permeability measurements is lost. Liquid permeability measurements, on the other hand, require no slip correction, but liquid saturation of the sample is time-consuming and difficult to insure. Often, too, the saturating liquid must be extracted or dried from the plug before it can be used for another experiment. The liquid Freon permeameter described herein retains the inherent accuracy of the liquid permeameter, while affording the speed and ease of operation of the gas permeameter. Freon-12 (dichlorodifluoromethane) is a halogenated hydrocarbon, immiscible in the liquid phase with water. It may be considered as an oil phase in laboratory fluid-flow studies. Like butane and propane, it is a gas at normal room temperatures and atmospheric pressure but can be liquefied at moderate pressures. Complete liquid saturation of a plug sample with any of these fluids can be easily achieved by condensing vapors in the sample and operating the permeameter at a pressure above the vapor pressure of the liquid. Freon-12 is superior to butane or propane for permeability measurements only in that it is relatively non toxic and completely incombustible, and thus presents no fire or explosion hazard. Freon-12 is believed to be completely nonreactive with most petroleum-reservoir rock samples. It volatilizes immediately from a plug on depressurizing to leave a clean, dry sample suitable for subsequent experiments. Thus, the inherent risk of changing physical properties of rock samples by cleaning and drying operations between permeability measurement and subsequent experiments is eliminated.

DESCRIPTION OF THE PERMEAMETER
The design of the liquid Freon permeameter is shown schematically in Fig. 1.
SPEJ
P. 18^
Solutions to Problems Drilling a High-Temperature, High-Pressure Well
Authors: Cassidy S. D. 
Published: December 2007

Summary
This paper is a case history of a deep, high-temperature, high-pressure (HTHP) well, drilled in the U.K. sector of the North Sea. The topics covered include the use of a vertical seismic profile (VSP) ahead-of-the-bit prediction combined with measurement-while-drilling (MWD) information to assist in picking a critical casing point. This technique permits penetration of the high-pressure transition zone without reaching a previously identified kick zone. Also discussed is an assessment of the suitability of different casing elevators to run a heavy casing string. New laboratory data indicate that some elevators will initiate localized yielding of the casing material at tensile loads much lower than those predicted by theory. Field data are presented that demonstrate the limitation on oil-based mud (OBM) circulating rates caused by flowline temperatures approaching the base oil flashpoint.
Although this material relates to a HTHP well, much of the information may be applied to improve the safety and efficiency of drilling operations in other deep, overpressured, or close-to-balance drilling environments.
A New, Effective Matrix Stimulation Diversion Technique
Authors: Paccaloni Giovanni 
Published: December 2007

Summary
This paper describes the theory and application of a new matrix stimulation diversion technique, maximized pressure differential and injection rates (MAPDIR), that uses injection rate as the key parameter to obtain sustained, planned bottomhole differential pressure, ∆p, levels. The technique, applicable wherever Darcy's law is valid (in sandstones and in unfractured or microfractured carbonatic reservoirs), favorably replaces diverting agents and extends to long intervals (&gt; 100 ft) the main advantage provided by mechanical zone isolation for "selective stimulation," which is maximized ∆p. The use of slightly viscosified stimulation fluids can further extend the range of application and improve the economics by reducing both the amount of hydraulic power and the fluid volumes required for stimulation. A multilayered reservoir case illustrates the application of the MAPDIR technique. A new log-log plot of skin evolution vs. injected-acid volume shows significant damage removal trends and provides important information for matrix stimulation treatment optimization. Field experience includes the successful treatment of horizontal pay intervals of up to 460 ft.
Because the real objective of diversion techniques is the effective removal of damage from the whole exposed pay, the meaning of "diversion" in this paper is not narrow (i.e., applicable only to diverting agents and ball sealers) but includes "placement" and "coverage" techniques, such as mechanical isolation, viscosified acids, and MAPDIR.
The Rejuvenation of the 30-Year-Old McAllen Ranch Field: An Application of Cross-Functional Team Management
Authors: Durrani A.J. , Escovedo B.M. , Ordemann Bill , Bickley J.A. , Tepper B.J. , Simon J.M. 
Published: December 2007

Summary
This case history overview describes the application of crossfunctional team management in redevelopment of a 30-year-old south Texas gas field. Multidisciplinary cooperation and synergism were emphasized, and efforts focused on a common team goal. The results have been extraordinary; all areas have shown significant improvement, including gas production, which is up by more than 250%.

Introduction
By the mid-1980's, McAllen Ranch field gas production had declined to a low of 24 MMcf/D owing to reservoir depletion and curtailment. The end of curtailment and subsequent development drilling activity increased the rate to 80 MMcf/D by early 1988. However, with reduced drilling and natural decline, the rate had fallen again to about 50 MMcf/D by early 1989.
At this time, a cross- functional team was established to evaluate additional investment opportunity and to develop a plan to increase production from the noncontributing reserves that were behind pipe. This team looked at all aspects of the field's production and developed a consensus plan that included acquisition, processing, and interpretation of a fine-grid 3D seismic survey; development drilling focused in the northern portion of the field (B-area); procedures to obtain regulatory approval to commingle noncontributing reserves in existing wellbores; and enhanced drilling and completion techniques.
This paper describes the interaction and synergism among the various specialties and functions involved in the producing operations at McAllen Ranch and how the concept of cross-functional team management has led to the rejuvenation of this 30-year-old field. It focuses on the process of cross-functional team management rather than just the results achieved.
Loads on Drillpipe During Jarring Operations
Authors: Aarrestad Thor V. , Kyllingstad Age 
Published: December 2007

Summary
Jarring implies heavy loads on the drillstring. The highest load on the drillpipe before jarring is at the rig floor. This paper discusses loads on drillpipe before, under, and after jarring. We show that for most situations, the shock wave from the jar impact does not imply additional load on the drillpipe compared with static load. The theoretical results are confirmed by measurements of a jarring operation with stuck point at ≈ 1200 m measured depth. Loads on the drillpipe can be a limiting factor in jarring operations because fear of possible additional loads from jarring dynamics may restrict the trip force (overpull) on the jar. Our main conclusion is that dynamic jar forces do not give additional loads on drillpipe. This information can be used to set an optimal trip force on the jar.
Amplification of Pulse-Testing Theory
Authors: Culham W.E. 
Published: December 2007

Pulse-testing theory as originally outlined is based Pulse-testing theory as originally outlined is based on the standard exponential integral solution to the radial form of the diffusivity equation. This paper presents a new solution to the subject diffusivity presents a new solution to the subject diffusivity equation and outlines how this type of solution can be used to clarify the "tangent construction method" of analyzing pulse data. The new solution is composed of a periodic part and a transient part. The splitting of the total solution into two parts facilitates the extension of pulse-testing to include steady-state conditions The differential equation and auxiliary conditions that define the periodic pulsing problem are
.......(1)
with the initial condition of
...........(2)
and boundary conditions of
.............(3)
.............(4)
where
............(5)
and H(t) is the unit step function. The solution to this boundary value problem is usually represented by the summation of appropriate exponential integral terms. A solution that splits the total solution into periodic and transient portions can be obtained as periodic and transient portions can be obtained as follows. Utilizing Laplace transform theory, the solution to Eqs. 1 through 4 is
................(6)
where, the real part of the complex integration limits, is taken large enough so that all singularities of the integrand lie to the left of the line ( - i, + i ). Complex variable theory was used to evaluate the integral in Eq. 6; and the final solution, in field units, can be shown to be
.........(7)
P. 1245
Oil Recovery From Bottomwater Reservoirs
Authors: Islam M.R. 
Published: December 2007

Introduction
Billions of barrels of oil remain unrecovered in "bottomwater" reservoirs with a highwater-saturation zone in communication with the oil zone. Typically, the water cut in such reservoirs increases rapidly during primary production, leading to low primary oil recovery. If a water zone were not present, many of these reservoirs would be good candidates for waterflooding. Instead, the performance is poor under conventional waterflood and worse if the oil is highly viscous. Several techniques and production strategies have been proposed recently to improve waterflood performance of such reservoirs. These are the subject of this paper.

Problems In Producing Bottomwater Reservoirs
Water coning is the most common problem in producing oil from a bottomwater reservoir. Once the water reaches the perforations, it is produced in preference to the more viscous oil, and the producing WOR becomes prohibitively high.
In heavy-oil formations, a high water cut often causes excessive sand deposits in the wellbore. A specific minimum oil flow rate is required to mobilize sand in most heavy-oil reservoirs. In most cases, with an increase in the water cut, the sand-carrying capacity of the produced fluids drops considerably and the wellbore sands up.
The detrimental effect of the bottomwater zone sometimes is alleviated by shale breaks, which reduce vertical permeability. A number of heavy-oil reservoirs with water legs have not been affected significantly by an underlying high-saturation water zone because of the presence of frequent horizontal shale breaks. Similar horizontal shale breaks probably will increase productivity in light-oil reservoirs with bottomwater as well.

Field Experience
The Bonnie Glenn field of Alberta is a light-oil bottomwater reservoir that has produced successfully under primary production. This light-oil (35 to 40 deg API) reservoir has a water zone, yet the oil production rate has been steady with little water influx from the bottomwater zone. One interesting feature of this reservoir is the presence of a gas cap. Also, the reservoir has a very high vertical permeability, resulting in an efficient gas cap drive with maximum pressure gradient from the top of the reservoir. As a result, oil can be produced with relatively small drawdown and minimum influx from the bottomwater zone. However, the reservoir is maturing after producing (with gas reinjection) some 80% of the original oil in place (OOIP). Currently reported WOR values are high.
Correlations of Gas-Oil Ratio History in a Solution-Gas-Drive Reservoir
Authors: Roberts Thomas G. , Ellis H. Edison 
Published: December 2007

Abstract
Instantaneous producing gas-oil ratio histories are calculated for a large number of hypothetical solution-gas-drive reservoirs from the basic data used by Arps and Roberts, and the results are presented in graphical form. A correlation is thus established wherein a typical GOR history can be obtained for a given gravity oil, with a given solution GOR, produced from a given type of reservoir rock.

Introduction
In 1955, Arps and Roberts presented the results of 72 solution-gas-drive recovery computations made on hypothetical reservoirs. The study covered six different types of reservoir rocks representing maximum, average and minimum conditions for sandstones and limestones. These six types of reservoir rock were assumed to be saturated with 12 synthetic crude-oil and gas mixtures representing oil gravities of 15 degrees, 30 degrees and 50 degrees API, and solution gas-oil ratios of 60, 200, 600, 1,000 and 2,000 scf/STB. The calculations, made using a Muskat-type differential equation, resulted in the relationship of stock-tank oil recovery (as a fraction of total pore volume) vs reservoir pressure for each hypothetical reservoir. From these data a correlation was developed between oil recovery and original solution GOR, API oil gravity and type of reservoir rock. The purpose of the present paper is to extend the original work of Arps and Roberts by presenting calculations of the instantaneous producing GOR histories for these same hypothetical sandstone reservoirs. The solutions representing the limestone cases have been omitted.

Gas-Oil Ratio Equation
The instantaneous producing gas-oil ratio R can be calculated by the following equation.
. . (1)
JPT
P. 595^
Some Effects of Contaminants on Real Gas Flow
Authors: Zana E.T. , Thomas G.W. 
Published: December 2007

In gas well testing and deliverability forecasting, failure to make corrections for contaminants can lead to intolerable errors. In general, where impurities exceed ten percent by volume, corrected values of the real gas pseudopressure function should be used.

Introduction
Isothermal gas flow through porous media has been the object of considerable study - the work, in general, deals with the flow of ideal gases and is therefore not generally applicable to gas reservoirs having low permeabilities or high reservoir pressures. This is because ideal gas flow treatment implicity assumes that pressure gradients in the system are small. Furthermore, the pressure dependence of gas viscosity and the gas law deviation factor are usually neglected. Recently, Al-Hussainy et al. presented a theory for real gas flow. Unlike previous work, theirs demonstrated that the pressure dependence of viscosity and the gas law deviation factor could be taken into account by expressing the gas flow equation in terms of a pseudopressure function. A nonlinear flow equation similar to the diffusivity equation was developed that did not require the assumption of small pressure gradients. In addition, a table of the real gas pseudopressure function was presented for gases containing pseudopressure function was presented for gases containing small amounts of contaminants. In a companion paper Al-Hussainy and Ramey showed how the real paper Al-Hussainy and Ramey showed how the real gas flow theory could be applied to standard gas well tests. Again, this study was limited to gases containing small amounts of contaminants. The purpose of our paper is to investigate some of the effects of gas contamination on real gas flow. Particular attention is devoted to constructing tables of Particular attention is devoted to constructing tables of the real gas pseudopressure function corrected for various amounts of nitrogen, carbon dioxide and hydrogen sulfide. Comparisons are made with the uncorrected results of Al-Hussainy et al. Finally, several example calculations are presented for some typical well tests, showing the errors that can occur in failing to make adequate corrections for gas contaminants.

Real Gas Flow Equations
For completeness, some of the development of Al-Hussainy and Ramey is included here. Principal assumptions are:Flow is isothermal and laminar.Gas composition is constant.The gas law is pV = znRT.The reservoir is homogeneous and isotropic.The formation has constant thickness and no dip. The equation for radial flow of a real gas is
(1)
Eq. 1 can be expressed in terms of the real gas pseudopressure function defined by pseudopressure function defined by
(2)
which yields
(3)
where cg(p)is the isothermal compressibility of gas given by
(4)
The pressure Pm is an arbitrary base pressure.
JPT
P. 1157
Optimizing the Distribution of Cathodic Protection Current
Authors: Roberson Glenn R. , Schremp F.W. 
Published: December 2007

Relative currents applied for a given potential may vary because of variations in distance from well to ground bed, in resistivities between wells and ground bed, and in pipe-to-soil resistance. Here is a simple method of measurement - more economical than the potential profile - that is sensitive to the variables and that makes it possible to compensate for them.

Introduction
In most instances wells are given cathodic protection on an individual basis. However, when well density is great, the interactions between cathodic protection systems and the electrochemical differences between wells cannot be overlooked. We shall discuss here various factors that affect the cathodic protection of well casings, and a procedure that can be used to optimize the distribution of cathodic protection current.

Methods of Current Distribution
Fig. 1 shows a typical control arrangement for a multiwell system. A variable rectifier generates a given total current output that is distributed according to a plan with the aid of a variable resistance at each well. The conductors may be flowlines, or they may be special conductors installed to carry the current. Fig. 2 illustrates, for each well, individual variable rectifiers that can be adjusted according to plan. In some cases two- to four-well systems are adjusted only by a central rectifier, and the current is allowed to flow to each well in inverse proportion to the resistance in that leg of the circuit.
Measurement of Current Requirements A number of methods have been used for measuring current requirements for each well. Following are some examples.E-Log I on a sampling or on all wells.Some variation of E-Log I.Potential profile data.Current density.Estimated economic limit.Some combination of these.
Of these methods, only the potential profile has enough sensitivity to give a measure of current requirement under operating conditions.

Variations in Current Requirement
Fig. 2 shows an installation with equal spacing between the wells and their individual ground beds. In actual practice, because of topographic adaptation or selection of ideal ground-bed soil, there is usually considerable variation in wellhead to ground-bed distances. In Fig. 3 the best ground bed is located close to two wells and distant from the other three. Fig. 4 shows the location of the ground bed in an almost ideal position; but two wells are in a subsurface salt water aquifer with the ground bed, and the other wells are not. Fig. 5 shows two wells where the low resistant area of the mud pit includes the upper casing and two where it does not. According to potential theory, the change in voltage (E) with distance (x) from a spherical anode is given by:
(1)
JPT
P. 812
A Short Cut to Stabilized Gas Well Productivity
Authors: Riley H.G. 
Published: December 2007

Here are simplified correlations that quickly provide correction factors for obtaining stabilized productivity from short-term flow tests. The only data needed to use the correlations are reservoir pressure, duration of test, and estimated permeability.

Introduction
For most studies involving gas wells and gas reservoirs, a very important consideration is the stabilized productivity or the ability to deliver gas for a productivity or the ability to deliver gas for a considerable time against a given backpressure. This knowledge is usually most needed in the early stages of development of an area, before extensive well test data or production information can be collected. Even in fields with considerable history, an engineer may frequently need a long-range performance prediction without having access to any data except the short-term test data normally required by state regulatory bodies. Short-term test data typified by a four-point back pressure with only 1 or 2 hours' flow on a point, or pressure with only 1 or 2 hours' flow on a point, or even a one-point 24-hour test may be grossly in error in low permeability reservoirs. Much of our nation's gas reserves is contained in the San Juan, Anadarko and Arkoma basins, which have the common characteristic of low permeability. In these areas it is not at all unusual for a well to require 30 days' flowing time to reach stabilization. Use of short-term test data for such wells would obviously lead to poor-quality estimates of either producing rates or reserves. The long-term flow test, to actually achieve stable flow, may be impractical for any of several reasons. The next best alternative would probably be two-rate flow tests. These require collection of detailed and closely controlled test data and can be costly even though much less time-consuming than the long-term flow to stable conditions. Another possible approach would be to determine interwell permeability and a skin factor from a pressure buildup test. Substitution of these factors with estimates of other reservoir parameters in the Darcy steady-state flow equation parameters in the Darcy steady-state flow equation would provide a reasonable estimate of stable flow capacity. In the absence of adequate field test data to define stabilized producing capacity, a stabilization factor to apply to short-term flow data would be useful; and that is the subject of this paper. For a stabilization factor to be most useful, it should be determinable with a minimum of field test data and calculation and still retain a reasonable degree of accuracy. Correlations have been developed that fulfill the requirement of minimum data and calculation. A check of the correlations with test data from several fields indicates a fair degree of accuracy.
Basis for Correlations The well known Darcy steady-state flow equation neglecting turbulence may be written for gas wells as follows:
(1)
This equation and all others here are in practical field units and the terms are in the nomenclature. In the equation s is the skin factor defined by van Everdingen.
JPT
P. 537