bluuebunny/crossref_metadata_2025_split huggingface dataset:
Real-Time and In-Situ Detection of Calcium Carbonate Scale in a West Texas Oil Field
Authors: Smith J. K. , Yuan M. , Lopez T. H. , Means M. , Przybylinski J. L. 
Published: December 2007

SummaryA novel technique has been developed to detect the onset and increase of calcium carbonate scale deposition from oilfield production fluids. This method uses an attenuated total reflectance (ATR) probe, called the scale sensor, to detect scale formation in situ. Because this method is based on existing technology and requires little supporting equipment, a simple, cost-effective monitoring device could be placed in many locations within a production system. This method could provide a system-wide, in-situ, real-time response to calcium carbonate scale formation at its earliest stages.As a first step toward evaluating the effectiveness of this new technology, the scale sensor was field tested at a west Texas oil field. The scale sensor was observed to detect the deposition of calcium carbonate under static and flowing conditions in actual produced fluids. In the static tests, crude oil, suspended solids, and other endogenous materials did not affect the scale sensor's response. Under flowing conditions, like those found in the production flowlines at this west Texas oil field, scale sensor response was observed to correlate to the chemical injection rate of both the scale inhibitor and the dispersant. On the basis of the results from the scale sensor, the scale inhibitor's injection point will soon be moved to the wellhead.
Theoretical Description of a New Method of Optimal Program Design
Authors: Miska Stefan , Skalle Pål 
Published: December 2007

Abstract
Drilling hydraulics have considerable effect on the rate of penetration. Previous studies have examined this problem; however, the effects of differential pressure and reliability of pumping equipment usually were neglected. This paper gives a general description of hydraulic drilling parameters optimized when both these effects were considered. To derive the necessary conditions for optimal hydraulics a nonlinear programming method was applied.
Identification of Steam-Breakthrough Intervals With DTS Technology
Authors: Johnson D. O. , Sugianto R. , Mock P. H. , Jones C. H. 
Published: December 2007

Summary
Steam breakthrough in producing wells can be very problematic. Not only can production drop drastically, but catastrophic failure events can occur; holes can be cut in tubulars, screens, and casing. Many of these events can result in loss of the borehole. Therefore, it is critical that the offending sand zone is identified quickly.
Many breakthrough-identification methods have been tried, including produced-well temperature, pulsed-neutron logging, and drilling observation wells to monitor zonal temperatures.
This paper discusses methods for installing optical fibers in oil and gas wells for distributed temperature sensing (DTS), the search to gain the considerable value offered by fiber-optic technology, and the development of an extremely cost-effective and accurate method that takes advantage of the power of DTS technology for determining steam breakthrough in producing wells.
Relative Permeability From Thermodynamics
Authors: Papatzacos Paul , Skjæveland Svein M. 
Published: December 2007

Summary
A new theory is reviewed for single-component, two-phase flow in porous media. It integrates thermodynamics with fluid mechanics and includes wettability in the thermodynamic description. It does not make use of the relative permeability concept. Wettability is included through a function that is part of the input to the model, together with an equation of state. A dialogue between this new model and the existing one has been established with the purpose of obtaining some of the input functions of both models. First, we have used information available in the existing model so as to calculate the function necessary for the description of wettability in the new model. The new model then being complete, we use it to find the two central functions necessary to the existing model, the relative permeabilities. We show that these are well defined when flow is characterized as a traveling wave, and we give a formula for their calculation. The formula assumes that a capillary pressure correlation and an equation of state are known, in addition to a constant related to the thickness of the transition region between the two phases.
Solubility of Sulfur in Hydrogen Sulfide and Sour Gases
Authors: Brunner E. , Woll W. 
Published: December 2007

Abstract
In recent years the search for natural gas has yielded many reserves that contain high concentrations of hydrogen sulfide.1 Production of sour gas initially was on a limited scale but since has increased considerably as a result of price increases for fossil fuels. Substantial quantities of sulfur now are produced from the hydrogen sulfide in these natural gas sources.
In several of these natural gas fields – e.g., in Canada and north Germany – gas production is hampered severely due to the presence of elemental sulfur dissolved in the gas. The gas-bearing deposits are interspersed with elemental sulfur, which is dissolved to a greater or lesser extent in the sour gas, the solubility being strongly dependent on the pressure, temperature, and composition of the gas. It is well-known that the solubility of sulfur increases with increasing pressure, temperature, and hydrogen sulfide content. As a result of the geothermal temperature profile, the gas stream cools as it rises up the production tubing and there is a drop in pressure due to frictional effects. Consequently, the solubility drops and sulfur is deposited when the solubility limit is exceeded. The gases dissolved in the liquid sulfur – principally hydrogen sulfide and carbon dioxide – lead to a lowering of the freezing point. At temperatures between 393.15 and 373.15 K, the sulfur begins to solidify in the line, blocking the tubing and bringing gas production to a standstill.
To prevent such blockages, suitable solvents are pumped into the well via an annular space surrounding the production tubing to dissolve the sulfur, which then is carried to the surface with the gas stream. A discussion of the technological problems involved in this process is beyond the scope of this paper.
Practicalities of Detecting Faults From Buildup Testing
Authors: Earlougher R.C. , Kazemi H. 
Published: December 2007

The influence of a sealing fault (and other linear discontinuities) on transient well tests is a widely discussed subject. The topic first was presented by Horner for pressure buildup testing. Fig, 1 illustrates ideal pressure behavior in a tested well near a fault. This figure is a schematic semilog plot that applies to any kind of single-well transient test; doubling of the straight-line slope is the key to the existence of a fault. The material presented in this paper applies to falloff and buildup tests. It does not paper applies to falloff and buildup tests. It does not apply to flowing-only tests, such as drawdown, injectivity, and multiple-rate flow tests. The information in this paper assumes horizontal radial flow in a homogeneous, unfractured reservoir and assumes that wellbore storage effects are unimporant.There an pitfalls in detecting faults (used here to mean any linear discontinuity) from pressure buildup and falloff tests that generally are not recognized. The reason is that flow time determines how much reservoir a test investigates. So, for a pressure buildup test, the flow time before shut-in determines if it will be possible to recognize a fault from buildup data. If flow time is long enough, then the shut-in time need only be long enough to obtain data that show the dope doubling. A shortflow time cannot be compensated for by a long shut-in time. Interestingly enough, the pressure behavior caused by a fault is such that if shut-in time is not long enough to show the double slope, it is possible to interpret the data incorrectly as indicating a small closed system rather than a large system with a nearby fault.Flow times too short to detect faults during buildup testing are particularly apt to occur in two common types of well testing. One is drillstem testing, which generally has a short flow period. The second is the testing of a gas well where no pipeline facilities are available, so a short flow period is used while the shut-in period may last weeks or months.The theory describing pressure behavior in a well near a fault is relatively simple. Fig. 1 shows pressure buildup curve shape and indicates that the pressure buildup curve shape and indicates that the second slope, m2, is twice the first slope, m1. From the first slope, one calculates skin factor and permeability. permeability. The doubling of the slope is a strict theoretical requirement and not an approximation.
P. 18
Handling Production-Data Uncertainty in History Matching: The Meren Reservoir Case Study
Authors: Kabir C. S. , Young N. J. 
Published: December 2007

SummaryHistory matching reservoir performance ordinarily implies adjusting geologic and rock-fluid flow properties until a satisfactory match is attained between the observed and model responses. Property adjustments inevitably imply a trial-and-error approach.Regardless of the approach used in any study, we presuppose the integrity of observed data. Unfortunately, measurements of gas and water do not have the desired precision when oil is the primary fluid of interest. For instance, when gas is flared, the quality of metering suffers. In some operations, withdrawal of small samples of a three-phase mixture near the wellhead becomes the sole basis for establishing water content in a production stream. These practices often introduce large uncertainty in the reported data of all three phases.This paper explores how we dealt with some of these issues while attempting to match 30-year performance in the Meren field in offshore Nigeria. Results show that production data affected by wellbore mechanical problems can be diagnosed with log-log type curves. Furthermore, this work shows that discerning water cut from wellhead samples is prone to errors, and issues with wellbore flow calibration can lead to large uncertainties in performance prediction. Identification of various issues helped mitigate the risks, leading to successful infill wells as testified by their production performance.
Materials Approach to the Development of Oilwell Cables
Authors: Wargin Robert V. 
Published: December 2007

Abstract
This paper presents and explains a chronological sequence of tests to gain an understanding of materials and construction requirements of electrical power cables for submersible motor pump (SMP) systems. A variety of simulated and actual downhole tests was run to examine the effects of time and temperature on the physical properties of insulation and jacketing materials. Pressure cycling effects on construction also were determined. The knowledge gained was applied to the development of a commercial electrical power cable.
The Twist and Shear of Helically Buckled Pipe
Authors: Mitchell Robert F. 
Published: December 2007

Summary
The effect of torque on buckling was first recognized while designing hollow propeller shafts for ships. If buckling could be caused by torque, then perhaps torque could be induced by helical buckling. This effect has not been extensively studied because the assumption has always been that the effect was too small to be of concern. This problem required an exact large-displacement solution to the helically buckled pipe because conventional small-displacement analysis has the built-in assumption that these effects are not important.
How significant are these effects? Lubinski et al.,1 in their paper on helical buckling, worked a sample problem of a squeeze cementing operation in 2⅞-in., 6.5-lb/ft tubing. The induced torque caused by helical buckling may exceed the makeup torque (in the range of 600 to 2,300 ft-lbf, depending on the grade) for large radial clearances, so induced torque in this problem may be high enough to break the connection!
This paper gives complete details for the torque and shear calculation in the Appendices. The body of the paper examines several typical tubing-load situations to evaluate the effect of induced torque and shear on a conventional design.
Phase Behavior of CO2 and Crude Oil in Low-Temperature Reservoirs
Authors: Orr F. M. , Yu A. D. , Lien C. L. 
Published: December 2007

Abstract
Phase behavior of CO2/crude-oil mixtures which exhibit liquid/liquid (L/L) and liquid/liquid/vapor (L/L/V) equilibria is examined. Results of single-contact phase behavior experiments for CO2/separator-oil mixtures are reported. Experimental results are interpreted using pseudoternary phase diagrams based on a review of phase behavior data for binary and ternary mixtures of CO2 with alkanes. Implications for the displacement process of L/L/V phase behavior are examined using a one-dimensional finite difference simulator. Results of the analysis suggest that L/L and L/L/V equilibria will occur for CO2/crude-oil mixtures at temperatures below about 120° F (49 °C) and that development of miscibility occurs by extraction of hydrocarbons from the oil into a CO2-rich liquid phase in such systems.
Generation of Low-Order Reservoir Models Using System-Theoretical Concepts
Authors: Heijn T. , Markovinovic R. , Jansen J.-D. 
Published: December 2007

SummaryWe present five methods to derive low-order numerical models of two-phase (oil/water) reservoir flow, and illustrate their features with numerical examples. Starting from a known high-order model, these methods apply system-theoretical concepts to reduce the model size. Using a simple but heterogeneous reservoir model, we illustrate that the essential information of the model can be captured by a limited number of state variables (pressures and saturations). Ultimately, we aim at developing computationally efficient algorithms for history matching, optimization, and the design of control strategies for smart wells. In this study we applied (1) modal decomposition, (2) balanced realization, (3) a combination of these two methods, (4) subspace identification, and (5) proper orthogonal decomposition (POD), also known as principal component analysis, Karhunen-Loève decomposition, or the method of empirical orthogonal functions. Methods 1 through 4 result in linear low-order models, which are only valid during a limited time span. However, the POD results in a nonlinear model that remains valid over a much longer period. Methods that result in linear low-order models are not very promising for speeding up reservoir simulation. POD, however, has the potential to improve computational efficiency in the case of multiple simulations of the same reservoir for different well operating strategies, but further research is required to quantify this scope. The potential benefit of low-order models is therefore mainly in the development of low-order control algorithms, and in history matching, where the use of reduced models may form an alternative to classical regularization methods.
Interplay of Phase Behavior and Numerical Dispersion in Finite-Difference Compositional Simulation
Authors: Jessen Kristian , Stenby Erling H. , Orr Franklin M. 
Published: December 2007

Summary
Compositional simulation of multicontact miscible (or nearmiscible) gas injection problems is typically performed by use of numerical finite-difference (FD) schemes. Such simulations are intrinsically affected by numerical dispersion.* In this paper, we propose a method to assess the sensitivity of a particular displacement calculation to the effects of numerical dispersion for systems with realistic multicomponent fluid descriptions. We use two simple ternary systems to illustrate how dispersion and convection interact to determine displacement composition paths and to define a "dispersive distance." We show how the dispersive distance relates to displacement performance with a detailed analysis of grid size effects on the recovery predictions for 1D displacements of a CH4-C4-C10 system by pure N2 and mixtures of N2 and CH4. We then show that the sensitivity of multicomponent compositional simulations also correlates well with the dispersive distance. We demonstrate that quantitative difference between oil recovery predicted by coarse-grid numerical simulations, and values obtained from analytical solutions to the conservation equations, can be estimated well from calculating the distance between the dilution line and the composition path predicted by the method of characteristics. Finally, we apply the assessment of sensitivity to 2D displacements in a heterogeneous porous medium to demonstrate the interplay of phase behavior, adverse mobility, heterogeneity, and numerical dispersion.
Experiments and Analysis of Heavy-Oil Solution-Gas Drive
Authors: Sahni A. , Gadelle F. , Kumar M. , Tomutsa L. , Kovscek A. R. 
Published: December 2007

Summary
We provide a general framework for interpreting heavy-oil solution-gas-drive experiments. Evolution of the gas phase below the thermodynamic bubblepoint is investigated with dimensionless scaling groups, mechanistic modeling, and experiments. Carefully planned and monitored depletion experiments are conducted to evaluate pre- and post-critical gas-saturation behavior. In-situ phase saturations are measured with X-ray computerized tomography (CT) scanning. These data are used in conjunction with differential-pressure measurements along the core to obtain phase mobilities. It is demonstrated that most laboratory heavy-oil-depletion experiments show nonequilibrium effects that depend on the oil-phase viscosity and depletion rate. Factors leading to the coalescence of gas-bubble clusters and development of bulk gas flow are illustrated with examples, along with an empirical correlation for critical gas saturation (Sgc). Examination of field-pressure gradients and flow rates suggests that dispersed gas flow may occur close to the wellbore or near wormholes, if present.
Identification of Mixtures of Waters from Chemical Water Analyses
Authors: McKinnell J.C. 
Published: December 2007

Abstract
Identification of complex mixtures of waters presents many problems that can be solved by graphical methods described in this paper. Examples are presented to show the application of these methods to the correlation of oilfield waters and the determination of the percentage of each water in mixtures of two and three waters.

Introduction
Correlation of waters and identification of mixtures of two and three waters is important in secondary recovery evaluation studies and studies involving underground movement of waters. The importance of such studies suggests the need for a method to correlate a great number of water analyses to accurately identify and improve the understanding of mixtures of waters.
Geochemical analyses of waters furnish a quantitative measure of each of the ions present in a water. Table 1 shows a portion of the data on many oilfield water analysis report forms in use today. Under "parts per million" are listed the quantitative amounts of each ion in milligrams per liter. Following the work of Stabler and Palmer, some laboratories have reported additional data to indicate the reaction capacity, or reacting value of each ion. Table 1 lists data under two subheads for the "reacting value". Under the first subhead, the reacting value is reported in gram equivalents per million, hereinafter called equivalents per million. This value is determined by multiplying milligrams per liter of the ion by a factor equal to the reciprocal of the equivalent weight of the ion. Under the second subhead (per cent) is listed the percentage of each ion based on the total equivalents per million.
Sodium is not usually an analyzed value in routine analyses, but is determined by the difference between total negative equivalent per million values and the sum of all of positive ion values for which analyses were made. This difference is reported as sodium, hereafter labelled "sodium". On this basis, the, subtotals of the equivalent per million and per cent reacting values of the positive and negative ions are equal.
Using Model Basin Tests to Predict Motion Characteristics of Floating Rigs
Authors: Beck R.W. 
Published: December 2007

Abstract
A scale model of a floating rig was subjected to motion tests in a wave basin under a variety of wave conditions representing actual wave heights and periods experienced in Lake Maracaibo in Venezuela. The motion of the rotary table relative to a fixed wellhead was recorded on motion picture film. The observed vertical, lateral and fore and aft motion was then related graphically to wave height and period. These data permitted predictions to be made that the actual floating rig would be able to work effectively more than 98 per cent of the time, and that the maximum motion to be expected under severe storm conditions would not endanger the floating rig, or the wellhead and foundation. The actual floating rig went into operation in mid-1963. It is equipped with a three-dimensional continuous motion recorder. During a prolonged test period, the floating rig operated effectively 99.44 per cent of the time, and the maximum motion experienced to date is 83 per cent of the theoretical maximum predicted from the model basin test data.
Introduction
Lake Maracaibo in Western Venezuela is a brackish body of water 110 miles long by 70 miles wide and a little over 100 ft deep. The Bolivar coastal field, one of the largest oilfields in the world, is in the northern half of the lake. Creole Petroleum Corp. is one of the major operators in Lake Maracaibo. A Creole drilling rig operating in the lake is shown in Fig. 1. The derrick and drawworks are mounted on a reinforced concrete pile foundation which has a working load capacity of 400 tons. The rest of the drilling equipment is carried on a standard drilling tender which is 180 ft long by 70 ft wide and has a normal operating displacement of about 2,700 tons. The heavy-duty foundation used on Creole's Lake Maracaibo wells represents about 30 per cent of the total well investment. If the foundations had to support only the wellhead and working platform and not the heavy drilling loads, a simplified tripod design could be used and the cost would be substantially reduced. With this in mind, Creole decided to examine the possibilities for converting a standard drilling tender to a floating rig by supporting the rig outboard of the front end of the barge. This system would permit the use of a tripod wellhead support platform costing only about one-half as much as a conventional foundation. Although it appeared probable that a floating rig of the type contemplated could be used successfully, it was deemed advisable to perform sufficient model basin tests to obtain quantitative answers regarding barge motion under the conditions to be expected in the lake.
Test Methods
The Model
Creole already had on hand an accurate 1:48 scale model of a standard drilling tender and drilling rig. A rig-support structure was prepared for the model so the rig could be mounted either over the bow or over the side. Photographs of the model rig are shown in Fig. 2.
JPT
P. 1361ˆ