bluuebunny/crossref_metadata_2025_split huggingface dataset:
Effect of Depletion Rate on Gas Mobility and Solution Gas Drive in Heavy Oil
Authors: Kumar R. , Pooladi-Darvish M. , Okazawa T. 
Published: December 2007

Summary
Some heavy oil reservoirs in western Canada and Venezuela show anomalously high primary recovery under solution gas drive process. The pressure decline rate in these reservoirs is low compared to that expected under solution gas drive in conventional oil reservoirs. There is now increasing evidence that gas mobility is extremely low in these reservoirs.
The objective of this study is to conduct solution gas drive experiments in a sandpack saturated with a heavy oil and examine the effect of depletion rate. Depletion rate was varied by more than two orders of magnitude. The results showed that gas mobility was a function of depletion rate and decreased with increasing depletion rate. Other notable observations were that supersaturation increased with depletion rate and that critical gas saturation was 3 to 4%, slightly increasing with increasing depletion rate.
Interpretation of the results confirmed that gas mobility is quite low. Representation of the low mobilities using relative permeability required low values of the order of 10−5–10−4, which decreased with increasing depletion rate.
Differential Scanning Calorimetry: A New Technique To Characterize Hydrate Formation in Drilling Muds
Authors: Dalmazzone Didier , Dalmazzone Christine , Herzhaft Benjamin 
Published: December 2007

Summary
With the increasing number of deep offshore drilling operations, operators and service companies are confronted by technical challenges ever growing in complexity. Extreme conditions encountered at these depths require an adaptation of the drilling muds. In particular, the range of temperatures and pressures encountered (as low as ‒1°C and up to 400 bar) is favorable for the formation of gas hydrates. Gas hydrates are solid structures formed from water and gas; water contained in drilling muds under certain temperature and pressure conditions will form solid cages that entrap the gas molecules. Formation of these solid gas hydrates is liable to plug kill and chokelines as well as the annular and may cause interruption of the drilling operation and even destruction of rig equipment. Deep offshore drilling operators are aware of this problem, and some operational solutions and drilling mud formulations have been proposed and utilized, but when extreme water depths are attained, classical inhibitor solutions alone may be ineffective. The usual way to determine the thermodynamic conditions of the formation of gas hydrates in drilling mud formulations is to use a pressure/volume/temperature (PVT) cell. This technique requires heavy instrumentation and often does not permit work with a whole formulation (especially in the presence of solids). Moreover, PVT cells do not give a quantitative evaluation of the kinetic properties of gas hydrate formation.
In this work, we present experiments using differential scanning calorimetry (DSC) to determine the thermodynamic equilibrium properties of methane hydrate in calcium chloride solutions. Additionally, thermograms of an emulsion and a complete drilling mud are presented that show the possibility of characterizing hydrate thermodynamics in complex systems as synthetic mud formulations. This technique is easy to use, and, when correctly interpreted, it enables the dangerous zones for hydrate formation to be determined.
Streamline Tracing on Curvilinear Structured and Unstructured Grids
Authors: Prévost Mathieu , Edwards Michael G. , Blunt Martin J. 
Published: December 2007

Summary
The streamline method has proven to be extremely successful for reservoir simulation.1 For a Cartesian grid, the standard five-point (seven-point in 3D) discrete pressure equation is employed within the IMPES streamline method. The accuracy of the velocity field plays a critical role in the success of the technique, which relies on precise determination of streamline paths.
Modeling complex geology and geometry requires the use of sophisticated grids, and thus the ultimate power of the streamline method will only be realized when the method is extended to general curvilinear grids.
In this paper, a generalization of the Cartesian tracing algorithm is developed for general tensor fields on structured (corner-point) grids and unstructured grids. The extension of the method requires the identification of appropriate volumes and fluxes over which tracing equivalent to the Pollock Cartesian method2 can be performed. Essential components of the method include the use of flux-continuous finite-volume schemes for the different grid types coupled with a novel flux recovery technique and a generalization of streamline tracing to polygons.
E&P Waste Management in the Orinoco Delta
Authors: Melchor A. E. , Costa A. da , Rodriguez C. , Peña J. R. 
Published: December 2007

Summary
Tropical wetlands and the presence of indigenous people with an ancient culture and a strong economic dependence on natural resources made the Pedernales field an environmental and socially sensitive location. BP's challenge was to work in this area without disrupting the lives of nearby settlements while preserving the environment.
The Pedernales field was designed as a zero-discharge operation in which the main waste streams were to be reinjected. However, the initial waste-management strategy had to be changed because of operational constraints to one that also allowed waste disposal in an environmentally sound way. Waste recycling, biotreatment, and temporary offsite treatment and disposal were key processes in the new waste-management strategy.
During 5 years of operation, a total of approximately 41.5×104 m3 of exploration and production (E&P) waste were handled and disposed of successfully. Poor area drainage combined with high annual rainfall and low natural soil-supporting capacity required using unconventional tools and equipment. This was especially needed for disposing of drill cuttings.
Drill cuttings were handled by turning them into slurry with a specially designed mixer, then pumping the slurry to a distance of up to 2 km from the storage barge. The cuttings originally contained up to 6% oil and grease but degraded to 1% within approximately 180 days. This is considered a short time with the high level of soil/waste moisture saturation taken into account. Continuously monitoring water and soil with a simple on-site laboratory proved to be adequate and cost-effective for process control and for preventing pollution.
Application of Low-Dosage Hydrate Inhibitors in Deepwater Operations
Authors: Fu B. , Neff S. , Mathur A. , Bakeev K. 
Published: December 2007

Summary
Novel low-dosage hydrate inhibitors (LDHI) have been developed for applications in oil and gas fields. A new generation of kinetic inhibitors has been used to prevent hydrate formation frequently encountered in deepwater operations. These chemicals effectively inhibit hydrate formation, regardless of the water cut in the system. They also exhibit a low toxicity that leads to very favorable environmental ratings. Valuable experience has been learned from recent laboratory studies and field trials with respect to the application limits and implementation techniques for these new products. The key to the overall success is a full integration of a good front-end design, a comprehensive deployment plan, and an effective monitoring program. An overview of the chemistry of these new inhibitors is discussed briefly along with their performance under simulated deepwater conditions. In addition, the effect of LDHI on hydrate formation and the effect of pressure on LDHI performance are addressed.
Kinetics of Silica Deposition From Simulated Geothermal Brines
Authors: Bohlmann E. G. , Mesmer R. E. , Berlinski P. 
Published: December 2007

Abstract
In our experiments, supersaturated brines were passed through columns packed with several forms of silica (crystalline α-quartz, polycrystalline α-quartz, and porous Vycor). Also, silica deposition on ThO2 microspheres and titanium powder was studied under controlled conditions of supersaturation, pH, temperature, and salinity. The residence time was varied by adjustments of flow rate and column length. The silica contents of the input and effluent solutions were determined colorimetrically by a molybdate method that does not include polymers without special pretreatment.
The following observations have been made.
Essentially identical deposition behavior was observed once the substrate was coated thoroughly with amorphous silica and the Brunauer-Emmett-Teller (BET) surface area of the coated particles was taken into account. The reaction rate is not diffusion-limited in the columns. The silica deposition is a function of the monomeric [Si(OH)4] concentration in the brine. The deposition on all surfaces examined was nucleated spontaneously. The dependence on the supersaturation concentration, hydroxide ion concentration, surface area, temperature, and salinity were examined. Fluoride was shown to have no effect at pH 5.94 and low salinity.
A cursory study of the effect of salinity showed little difference for 0.09 and 1.0 molal NaCl solutions; however, increasing the concentration to 4.0 molal increased the deposition rate by more than one order of magnitude. The empirical rate equation that describes our data in 1 molal NaCl in the pH range 5 to 8 and temperatures from 60 to 120°C is
(1) − d [ Si ( OH ) 4 ] d t = 0.12 A { [ Si ( OH ) 4 ] − [ Si ( OH ) 4 ] e } 2 [ OH − ] 0.7 ,
where A is the amorphous SiO2 surface area in square centimeters per kilogram of water in column voids; t is minutes; and the concentrations are in molal units. Hydroxide concentration was derived from the measured pH and the ionization quotient for water. In the expression given above, the rate constant is essentially independent of temperature over the range 60 to 120°C.
Radial Steam Flow in Two-Phase Geothermal Reservoirs – Comparison of Analytical and Finite Difference Solutions
Authors: Moench Allen F. 
Published: December 2007

Abstract
A linear closed-form analytical solution for the radial flow of steam toward a producing well in a vapor-dominated geothermal reservoir is compared with a finite difference solution to the nonlinear equations of fluid flow and energy change. Assumptions used in the development of the equations are that (1) the liquid phase, initially uniformly distributed within the reservoir, is immobile, (2) the relative permeability to steam is constant, (3) local thermal equilibrium exists within the reservoir, (4) temperature changes are due only to phase change, and (5) effects of vapor-pressure lowering are negligible. With the onset of production, vigorous vaporization of liquid water in the reservoir near the wellbore creates a dry region that increases in volume as production continues. This behavior produces a circular moving boundary that separates superheated steam in the dry zone from saturated steam in the wet zone. The rate of movement of this boundary, the pressure drawdown, and the temperature and saturation distributions are obtained analytically by applying the solution to the linearized equations of flow in radial coordinates. Results obtained numerically using a finite difference solution to the nonlinear equations of fluid flow and energy agree closely with the analytical approach in spite of the nonlinearities involved.
Selective Absorption of H2S From Sour Gas
Authors: Hohlfeld R.W. 
Published: December 2007

Selective absorption of H2S from sour gas with caustic by gas/liquid scrubbing is a new approach for oilfield operations to meet environmental and safety restrictions. This technology demonstrates that by maintaining a very short contact time in a gas/liquid scrubber it is possible for caustic to react with and remove H2S from a sour gas.

Introduction
Hydrogen sulfide (H2S) and carbon dioxide (CO2) are natural contaminants of gases from well casings, combustion floods, geothermal steam, or process streams. Because of safety, environmental or corrosion considerations, it normally is desirable to remove the H2S from such gases. However, these factors do not dictate the removal of CO2, and it is not desirable because of the cost involved. Safety standards set by the U.S. Occupational Safety and Health Admin. limit worker exposure to H2S at 10 ppm for an 8-hour day. Environmental guidelines ppm for an 8-hour day. Environmental guidelines require limited sulfur emissions, particularly of H2S, which has a characteristic "rotten egg" odor at levels of 3 ppm. Corrosivity of wet H2S gases is well known because of its acidic character.
Many commercial methods exist to remove H2S from sour gas streams, though they all have their limitations. Some processes may be limited by the volume of gas they can handle or by the level of H2S or CO2 in the gas stream. Others may prove to be costly because of the capital investment or operating expense. Still others are not suitable for the field because of the complexity of operation, requiring highly trained personnel.
In the H2S removal system described in this paper, these objections largely are overcome, as evidenced by a number of production units based on this technology. Experience has shown that this system (1) has a very low capital investment cost (2) has a simple design based on gas/liquid scrubbing (3) has straightforward installation and operation (4) will remove H2S efficiently, and (5) can treat gases widely varied in composition and volume. These units have proved effective in H2S removal from operations as widely divergent as pipeline-quality gas plants to remote locations treating vent gases with plants to remote locations treating vent gases with 10% H2S.

Theory
The principle of the technology presented here is based on a patent issued to The Dow Chemical Co. It states (and is reduced to practice in the method discussed here) that H2S can be absorbed selectively from sour gases also containing CO2 by maintaining a proper residence contact time between the gas and an alkaline liquid. Normally, in a typical wet scrubbing operation both acidic gases (H2S and CO2) would be absorbed. However, the absorption and reaction of H2S in a strongly alkaline solution (caustic soda) is virtually instantaneous while the absorption of CO2 is a much slower reaction. Thus, if the gas is allowed to contact the liquid for a controlled short time, the CO2 absorption and reaction with caustic will be insignificant. Because H2S does not have this limitation, it is absorbed preferentially. preferentially. JPT
P. 1083
Potential Application of Amine Methylene Phosphonate-Based Inhibitor Species in HP/HT Environments for Improved Carbonate Scale Inhibitor Performance
Authors: Graham G. M. , Dyer S. J. , Shone P. 
Published: December 2007

Summary
In recent years, a number of new high-pressure/high-temperature (HP/HT) reservoirs have been developed in the North Sea [for example, the Eastern Trough Area Project (ETAP) and Shearwater fields] that have several important scale-control issues. In addition to their ability to prevent scale formation, these include inhibitor/ brine compatibility and the thermal stability of the scale inhibitor. Previous works have strongly indicated that amine methylene phosphonic acid-based inhibitor species, such as pentaphosphonate (DETPMP) and hexaphosphonate (TETHMP), are considerably less thermally stable than polymeric species, such as PVS and the S-Co species. As a consequence, the phosphonate-based species have been reported as less applicable for deployment in high-temperature reservoir systems. However, more recent studies that examined a range of different amine methylene phosphonic acid-based inhibitor species have shown that certain species are thermally stable at temperatures exceeding 160°C. This paper presents the initial screening study undertaken to select a scale inhibitor for the Shearwater reservoir and includes an examination of some phosphonate species to determine potential application in HP/HT reservoir systems.
Asphaltene Characterization and Mitigation in South Kuwait's Marrat Reservoir
Authors: Kabir C. S. , Jamaluddin A. K. M. 
Published: December 2007

SummaryThis study addresses two aspects for mitigating production problems in south Kuwait's Marrat wells in the Magwa area of the Greater Burgan field.Characterizing single-phase oil samples collected from four wells. Finding a pragmatic and cost-effective solution to tubular-deposition problems.We took two approaches for laboratory investigation. In the first approach, a gravimetric technique was used to establish asphaltene onset pressures (pao) at various temperatures, leading to the generation of the asphaltene flocculation envelope (AFE). The second approach entailed the use of acoustic resonance technique (ART) for rapid determination of both pao and bubblepoint pressure (pb) in one experimental run en route to the development of a solvent— deasphalted oil.Fluid characterization also included thermodynamic modeling. Asphaltene is treated here as a solid phase in equilibrium with the reservoir fluid, which is modeled by an equation-of-state (EOS) model. We reproduced the observed features of various isotherms quite well, lending credence to the modeling approach.Following fluid characterization, we sought a cost-effective and environmentally friendly solvent. The search for a solvent led us to the development of deasphalted oil. We designed and conducted a series of experiments to deasphalt the Marrat oil and examine its potency as a solvent. Results showed that the use of 20% deasphalted oil with 1% dispersant, both by volume, can ensure solubility of asphaltenes in the entire flow string during production. EOS modeling on deasphalted oil was also done for computing onset pressures at various temperatures with good success. Field trial results are also included to show its partial success in well-bore remediation.
The Accuracy of PVT Parameters Calculated From Computer Flash Separation at Pressures Less Than 1,000 psia
Authors: Glaso O.S. , Whitson C.H. 
Published: December 2007

Introduction
Standing derived a set of equations that fit the equilibrium constant data of Katz and Hachmuth at pressures less than 1,000 psia (6.895 MPa) and pressures less than 1,000 psia (6.895 MPa) and temperatures below 250 degrees F (121 degrees C). A standard deviation (SD) of 3.5% between calculated and chart K values is reported by Standing. Not reported, however, is the accuracy of the Katz and Hachmuth K values applied to reservoir fluids of various paraffinicities and containing significant amounts of nonhydrocarbons. Because the data of Katz and Hachmuth were for an Oklahoma City crude oil containing no nonhydrocarbons, it was necessary to investigate their general applicability. A separator flash program was developed that incorporates the Standing K-value equations. The program was used to analyze 15 crude oils from various regions of the world, some containing substantial amounts of nonhydrocarbons. Flash parameters were calculated and compared with experimental values obtained from a PVT analysis of the fluid samples. GOR, average gas PVT analysis of the fluid samples. GOR, average gas gravity, stock-tank oil gravity, and bubble-point formation volume factor were used in the comparisons.

Flash Program Description
Our vapor and liquid equilibrium calculations involved use of the Katz and Hachmuth K values fitted by Standing. The algorithm used for calculations is described by Standing. The basic equation for fitting K-value data given by Hoffman et al. was used in this study:
.......................(1)
where coefficients a and c are functions of separator pressure. Psp is measured in psia, and F is a pressure. Psp is measured in psia, and F is a characterization factor. Equations for constants a and c appear in Ref. 1. The characterization factor, F, as defined by Hoffman et al., is
........................(2)
where separator temperature, Tsp, is in R, Tb is the average boiling-point temperature in R, and coefficient b is defined for the pure components C3, iC4, nC4, iC5, nC5, and C6 as
........................(3)
All other fractions except C7+ (i.e., C1, C2, CO2, N2, and H2S) have modified values of b and Tb, and these values can be determined by the procedure outlined in Ref. 1. The K value for the C7+ fraction was determined by the equation
.............................(4)
where KC7 was calculated as a pure component. Ref. 1 provides an alternative method to determine KC7+. This provides an alternative method to determine KC7+. This method was not available to the authors at the time this study was conducted. We recommend that the procedure given in Ref. 1 be used to determine KC7+. A check was made to see what, if any, error resulted from using Eq. 4. It was found that there is no significant loss of accuracy in calculated flash parameters unless the oil contains a large C7+ fraction (greater than 0.70).
JPT
p. 1811
An Experimental Study for Mechanical Formation Damage
Authors: Soares A. C. , Ferreira F. H. , Vargas E. A. 
Published: December 2007

Summary
This work presents triaxial experiments that were carried out in different stress paths, with measurements of P- and S-wave acoustic velocity and permeability, to evaluate mechanical formation damage. In some reservoirs, large deformations occur during oil production because of the effective stress increase. This may cause permanent damage to the reservoir as the rock structure changes, lowering the permeability and the final oil recovery. The experiments showed that plastic behavior is always present and that a "cap" model may represent the yield region. This methodology allowed a near-wellbore evaluation and permeability investigations using a stress-path concept.
Some Rock-Mechanical Aspects of Oil and Gas Well Completions
Authors: Geertsma J. 
Published: December 2007

Abstract
Elementary borehole- and perforation-stability problems in friable clastic formations for unrestricted fluid flow between reservoir rock and underground opening are treated on the basis of linear poroelastic theory. Thermal stress effects caused by a temperature difference between reservoir and borehole fluids can be predicted from the mathematical similarity of poro- and thermoelasticity. A tension-failure condition applies for the prediction of hydraulic fracture initiation in a formation around injection wells. The resulting equations are partially well-known.
Similarly, a uniaxial compression-failure condition should predict perforation failure leading to sand influx in production wells. The major difference between these situations is that, at sufficient depth of burial, the tensile strength of a friable rock mass has only a minor effect on the fracturing pressure level, but the actual value of the compressive strength plays a crucial role in the prediction of sand-influx conditions. Practical suggestions for resolving the latter are given.
Deformation of Chalk Under Confining Pressure and Pore Pressure
Authors: Blanton Thomas Lindsay 
Published: December 2007

Abstract
Compression tests with and without pore pressure have been run on Danian and Austin chalks. The rocks yielded under increasing hydrostatic stress by pore collapse. The same effect was produced by holding a constant hydrostatic stress and reducing the pore pressure. This pore collapse reduced the permeability. The ultimate strength of the chalks increased with increasing confining pressure. The yield strength increased initially, but at higher confining pressures it decreased until it yielded under hydrostatic stress. Relatively high pore-pressure gradients developed when the chalks were compressed. In these situations, the mechanical behavior tended to be a function of the average effective stresses.