bluuebunny/crossref_metadata_2025_split huggingface dataset:
Scale Prediction for Oil and Gas Production
Authors: Kan Amy T. , Tomson Mason B. 
Published: November 2012

SummaryScale prevention is important to ensure continuous production from existing reserves that produce brine. Wells could be abandoned prematurely because of poor management of scale and corrosion. The objective of this paper is to present an overview of scale prediction and control and the current research at Rice University to solve these problems. In this paper, the challenges of scale prediction at high temperature, high pressure, and high total dissolved solids (TDS) and an accurate model to predict pH, scale indices, density, and inhibitor needs at these conditions are discussed and reviewed: specifically discussed are (1) the various scale types found in oil and gas production and the condition under which they form; (2) the relationship of pH, alkalinity, organic acids, carbonates, and CO2 distribution; (3) the temperature (T), pressure (P), TDS dependence of the thermodynamic equilibrium constants and activity coefficients; and (4) the accuracy of the Pitzer ion-interaction model-based scale-prediction algorithms and their application. On the basis of a simple propagation of error estimation, the overall estimated error for calcite saturation index (SI) is ± 0.1. This algorithm has been validated with literature solubility data for six minerals in the T, P, and TDS range of 0 to 200°C, 0 to 15,000 psia, and 0 to 350 000 mg/L TDS; for pH data at 25 and 60°C; and density of weighting fluids with density between 8 and 12.7 lbm/gal.
Geomechanical Risk Assessments for CO2 Sequestration in Depleted Hydrocarbon Sandstone Reservoirs
Authors: Fang Z.. , Khaksar A.. , Gibbons K.. 
Published: November 2012

Summary
Depleted hydrocarbon reservoirs are attractive targets for gas storage and carbon dioxide (CO2) disposal because of proven storage capacity and seal integrity, existing infrastructure, and other reasons. Optimum well completion and injection design in depleted reservoirs would require understanding of important rock-mechanics issues considering rock/fluid-interaction effects (e.g., drillability and completion of new wells, maximum-sustainable-storage pressures avoiding fracturing, and fault reactivations). Building a field-specific geomechanical model calibrated with well and production data is a prerequisite for addressing these issues. Through a case study, this paper demonstrates a systematic approach for geomechanical risk assessments for CO2 storage in depleted reservoirs.
A depleted gas reservoir at a 4,050-ft depth with the current pressure of 45 psi is considered in this study for CO2 sequestration. The study used offset-well drilling and wireline-log data to derive field stresses, formation pressure, rock strength, and elastic properties. A practical workflow was developed to characterize the interaction between pressure depletion and fracture-gradient changes. In this particular case, the results showed that the fracture gradient (FG) was as low as approximately 9.3 lbm/gal, and the wellbore-collapse pressure in the overburden shale was highly dependent on the well trajectory. If an operating mud-weight window of 0.5 lbm/ gal is required, the well inclination should be below 65° if it is planned to be oriented toward the minimum-horizontal-stress (Shmin) direction, or less than 45° if toward the maximum-horizontal-stress (Shmax) direction, to mitigate drilling risks. Field data and analytical-sanding evaluations indicate no sand-control installation would be needed for injectors. Fracturing and faulting assessments confirm that the critical pressures for fault reactivation and fracturing of caprock are significantly higher than the planned CO2-injection and -storage pressures. However, the initial CO2 injection could lead to a temperature in the near-wellbore region as low as 0.7°C. There is a high risk that a fault with cohesion of less than 780 psi could be activated because of the significant effect of reduced temperature on field stresses, and it is therefore recommended that the CO2 injectors be placed in fault-free regions.
The methodology and overall workflow presented in this paper are expected to assist well engineers and geoscientists with geomechanical assessments for optimum well-completion and injection design for both natural-gas and CO2 storage in depleted reservoirs.
Deconvolution of Pressure and Rate Data From Gas Reservoirs With Significant Pressure Depletion
Authors: Levitan M.M.. M. , Wilson M.R.. R. 
Published: November 2012

SummaryDeconvolution is a technique for converting the pressure and rate data obtained from a well operating under variable-rate conditions into a much simpler form of constant-rate drawdown-pressure response function from the same well. However, deconvolution should only be applied to pressure and rate data that result from fluid flow in the reservoir that is governed by a linear set of equations. In gas reservoirs, the fluid-flow problem is nonlinear because the gas properties are strongly dependent on pressure. In some specific situations, this gas-flow problem can be linearized by the use of a pseudopressure transform that allows deconvolution to be successfully applied to tose data. However, there are situations in which a pseudopressure transform alone does not fully linearize the gas-flow problem, and the resulting data will exhibit nonlinear behavior caused by the pressure dependence of the gas compressibility. Direct application of deconvolution to such data will produce erroneous results.This paper presents an enhancement of the deconvolution algorithm that allows it to be used with pressure data affected by a nonlinear pressure-dependent compressibility. We discuss the detailed considerations for this enhancement of the deconvolution algorithm and demonstrate its performance on simulated test data exhibiting this nonlinear behavior. We also demonstrate the application of this enhanced deconvolution algorithm to a set of pressure data from a gas well fitted with a permanent gauge and covering the first 3 years of production from that well.
Can Formation Relative Permeabilities Rule Out a Foam EOR Process?
Authors: Ashoori E.. , Rossen W.R.. R. 
Published: November 2012

Summary
Foam is a promising means of increasing sweep in miscible- and immiscible-gas enhanced oil recovery (EOR). Surfactant alternating gas (SAG) is a preferred method of injection. Numerous studies verify that the water relative permeability function krw(Sw) is unaffected by foam. Studies of foam have used a variety of krw functions.
This paper shows a connection between the krw(Sw) function and SAG foam effectiveness that is independent of the details of how foam reduces gas mobility. For simplicity, we analyze SAG processes in the absence of mobile oil; success without oil is a precondition to success with oil, and our analysis also applies to a miscible-gas process with oil in 1D in the absence of dispersion.
Fractional-flow methods have proved useful and accurate for modeling foam EOR processes. The success of SAG depends on total mobility at a point of tangency to the fractional-flow curve, which defines the shock front at the leading edge of the foam bank. One can determine total mobility directly from the coordinates of this point (Sw, fw) if the function krw(Sw) is known.
Geometric constraints limit the region in the fractional-flow diagram in which this point of tangency can occur. For a given krw(Sw) function, this limits the mobility reduction achievable for any possible SAG process. We examine the implications of this limitation for different krw functions.
These implications include the following. Increasing nonlinearity of the krw function is advantageous for SAG processes, regardless of how foam reduces gas mobility. SAG is inappropriate for naturally fractured reservoirs if straight-line relative permeabilities apply, even if extremely strong foam can be stabilized in fractures. It is important to measure krw(Sw) separately for any formation for which a SAG process is envisioned.
Estimating the Specific Productivity Index in Horizontal Wells From Distributed-Pressure Measurements Using an Adjoint-Based Minimization Algorithm
Authors: Farshbaf Zinati F.. , Jansen J.D.. D. , Luthi S.M.. M. 
Published: November 2012

Summary
Recent developments in the deployment of distributed-pressure-measurement devices in horizontal wells promise to lead to a new, low-cost, and reliable method of monitoring production and reservoir performance. Practical applicability of distributed-pressure sensing for quantitative-inflow detection will strongly depend on the specifications of the sensors, details of which were not publicly available at the time of publication. Therefore, we theoretically examined the possibility of identifying reservoir inflow from distributed-pressure measurements in the well. The wellbore and nearwellbore region were described by semianalytical steady-state models, and a gradient-based inversion method was applied to estimate the specific productivity index (SPI) as a function of along-well position. We employed the adjoint method to obtain the gradients, which resulted in a computationally efficient inversion scheme. With the aid of two numerical experiments (one of which was based on a real well and reservoir), we investigated the effects of well and reservoir parameters, sensor spacing, sensor resolution, and measurement noise on the quality of the inversion results. In both experiments, we generated synthetic measurements with the aid of a high-resolution reservoir-simulation model and used these to test the semianalytical inversion algorithm. In the first experiment, we considered a 2000-m horizontal well passing through two 300-m high-permeability streaks in a background with a permeability that was 10 times lower. The location of the streaks and the SPIs along the well were detected with fair accuracy using 20 unknown parameters (SPI values) and 20 pressure measurements. Decreasing the number of measurements resulted in a poorer detection of the streaks and their SPIs. The detection performance also decreased for increasing noise levels and deteriorated sensor resolution, though the negative effect of random measurement noise was cancelled out primarily by stacking multiple measurements. The detrimental effects of measurement noise and low sensor resolution were strongest in areas where the inflow was lowest (usually close to the toe). The second experiment concerned a high-rate near-horizontal well with slightly varying inclination that intersected a dipping package of formations with strongly variable permeabilities. Additionally, a satisfactory detection of SPIs was obtained even though the heterogeneities were no longer perpendicular to the well as in the first experiment. As a result of using the simple semianalytical forward model and the adjoint method, the inversions typically required less than 90 seconds on a standard laptop. This offered the opportunity to extend the algorithm to multiphase flow and dynamic applications (pressure-transient testing), while still maintaining sufficient computational speed to perform the inversion in real time.
Meeting the Challenges in Downhole Scale Control for High-Water-Production Horizontal Wells in an Environmentally Sensitive Part of the Norwegian North Sea
Authors: Chen P.. , Montgomerie H.. , Hagen T.. , Vikane O.. , Juliussen B.. , Håland T.. , Nguyen K.. , Chen T.. 
Published: November 2012

Summary
As a result of the seawater injections in one of the Norwegian North Sea oil fields, sulfate-scale depositions have been identified in the near-wellbore region and inside the production well. Scale-inhibitor squeeze treatments are carried out regularly. Most of the production wells are horizontal producing, with a fairly high water cut, and increasing the squeeze treatment life is one of the major issues for the selection of scale inhibitors and placement technologies. In addition, the inhibitor selected has to be environmentally acceptable and meet regulations from environmental authorities. Both challenges from the high-water-production wells and environmental requirements limited the choice of the inhibitor candidate selections.
Through extensive laboratory qualification testing, a newly developed polymer inhibitor was qualified for the field and satisfactory results were achieved from several field trials. This paper presents the inhibitor chemistry, as well as laboratory tests such as inhibitor efficiency and compatibility and inhibitor coreflood. The environmental properties of the chemistry will be outlined. A comparison was made between the field treatments using this polymer inhibitor and widely applied polymer chemistries. The treatment optimization using a software package will also be highlighted. The field used a gelled scale-inhibitor package, and the technology improved the inhibitor placement in the horizontal well. The updated treatment data will be reviewed in this paper.
Simulation of Flow and Dispersion on Pore-Space Images
Authors: Mostaghimi Peyman , Bijeljic Branko , Blunt Martin J. 
Published: November 2012

Summary
We simulate flow and transport directly on pore-space images obtained from a microcomputed-tomography (micro-CT) scan of rock cores. An efficient Stokes solver is used to simulate low-Reynolds-number flows. The flow simulator uses a finite-difference method along with a standard predictor/corrector procedure to decouple pressure and velocity. An algebraic multigrid technique solves the linear systems of equations. We then predict permeability, and the results are compared with lattice-Boltzmann-method (LBM) numerical results and available experimental data.
For solute transport, we apply a streamline-based algorithm that is similar to the Pollock algorithm common in field-scale reservoir simulation, but which uses a novel semianalytic formulation near solid boundaries to capture, with subgrid resolution, the variation in velocity near the grains. A random-walk method accounts for molecular diffusion. The streamline-based algorithm is validated by comparison with published results for Taylor-Aris dispersion in a single capillary with a square cross section. We then predict accurately the available experimental data in the literature for the longitudinal dispersion coefficient for a range of Péclet numbers (10–2 to 105). We introduce a characteristic length on the basis of the ratio of volume to pore/grain surface area that can be used for consolidated porous media to calculate the Péclet number.
Optimization of a Solid-Acid Precursor for Self-Destructing Filter Cake
Authors: Rostami Ameneh , Nasr-El-Din Hisham A. 
Published: November 2012

Summary
This paper presents technology for water-based drilling fluid that is weighted with calcium carbonate particles. This technology has functions of both drilling and completion, and can reach the total depth of maximum-reservoir-contact (MRC) wells. It creates a filter cake that prevents fluid leakoff during the drilling process, but readily cleans up the filter cake over time. This technology is based on the use of an ester, in a solid form, which hydrolyzes and produces an organic acid. The latter will dissolve calcium carbonate particles that are used as a weighting material in water-based drilling fluids. Polylactic acid (PLA) particles were used in this study to generate lactic acid.
Experiments were conducted to find an optimum particle size of the solid ester and calcium carbonate particles that should be selected as a compromise between those that are optimal for fluid-loss control or filter-cake formation and those that are optimal for self-destruction at the desired time and rate. Other sets of experiments were conducted to determine the optimal temperature and soaking time required for the solid ester to hydrolyze and for the resulting acid to dissolve calcium carbonate particles.
All experiments showed that in controllable conditions of temperature, acid concentration, and particle size, the cleanup efficiency exceeded 70%. The optimum particle size was found to be 50 μm for calcium carbonate and 150 μm for PLA. The optimum temperature was 230°F. These conditions will ensure high filter-cake-removal efficiency, low filtrate volume, and no returned-drilling-fluid or high-viscosity problems. Ample soaking time is needed for PLA to hydrolyze and for the generated acid to remove the filter cake (i.e., 20 hours).
Use of a Mechanistic Model To Forecast Cement-Sheath Integrity
Authors: Bois Axel-Pierre , Garnier André , Galdiolo Grégory , Laudet Jean-Benoît 
Published: November 2012

SummaryTests performed in the laboratory have shown that there exist two types of mechanisms that could lead to loss of cement-sheath integrity: mechanical degradation, when cement is submitted to compressive or tensile loadings that are too high compared with its strength, and chemical degradation. The worst case is when both mechanisms occur at the same time or one after the other. For example, a cement sheath that is damaged before entering into contact with a degrading fluid will allow this fluid to penetrate deeper into the cement sheath, hence accelerating cement chemical degradation.As a consequence, it is of paramount importance to understand the mechanisms that could lead to loss of cement-sheath integrity before any chemical degradation occurs. It is with this objective that a mechanistic model was developed to simulate the various modes of loss of cement-sheath integrity after cement has been placed: (a) cement volume variations during hydration owing to chemical shrinkage/expansion; (b) cement volume-variations during hydration owing to cement heat-production; (c) contraction (dilation) of the casing owing to a decrease (an increase) in mud density/temperature; (d) cement volume decrease owing to pore collapse; and (e) thermal cycling.This paper has two objectives: (1) present the mechanistic model and (2) on the basis thereof, show that loss of cement-sheath integrity depends not only on cement properties but also on the well architecture and well history.
A New Way of Staged Fracturing Using Ball Sealers
Authors: Wang Da , Wang Xingzun , Liu Gangzhi , Economides Michael J. 
Published: November 2012

Summary
Technologies for horizontal-well fracturing in China include multistaged fracturing and hydraulic jetting. As in many other parts of the world, this type of well stimulation employs mechanical zonal isolation or sand and polymer plugs. All of these technologies are used by us in a number of reservoirs, but they depend on the presence of newly targeted and intentionally perforated sections of horizontal wells that are not already perforated. However, because most horizontal wells in the mature Huabei oil field have been producing for a very long time and the perforations are all along the horizontal sections, it is practically impossible to use these technologies.
To prevent multiple-fracture initiation in a given section, sealing-ball staged fracturing has been developed and used successfully in horizontal wells of the Huabei field. Three kinds of sealing balls—with densities of &lt;1, 1, and &gt;1 g/cc, respectively—are pumped between stages of fracturing. They can seal perforations 360° around the horizontal-well section. Higher-permeability zones are sealed off preferentially. Because staged fracturing can be carried out effectively without stopping the pumps while running ball sealers downhole, the process can be accomplished in a significantly shorter period of time than other techniques. And, because these sealing balls are made of wax, they can be dissolved and removed later by the oil produced from the formations.
In this paper we present field case studies of staged hydraulic fracturing using ball sealers, and we demonstrate the success of this form of zonal isolation in both execution and especially postfracture well performance. We also provide guidelines for the effective length of horizontal-well section in which ball sealers can be used for zonal isolation.
Enhancing Production by Removing Zinc Sulfide Scale From an Offshore Well: A Case History
Authors: Berry Sandra L. , Boles Joel L. , Singh Amit , Hashim Imran 
Published: November 2012

Summary
Deposition of mineral scales is the root cause of many production problems in oil and gas operations. These scale deposits have resulted in formation damage, production losses, significant rate and pressure reductions, and equipment failure because of corrosion issues. The most commonly encountered mineral scales in the oil field are carbonates and sulfate-based calcium sulfate, barium sulfate, and strontium sulfate scales. However, a more unusual form of these mineral scales, zinc sulfide, has recently been reported.
This paper focuses on the systematic study of a zinc sulfide scale and the operation that removed it from a well in the Gulf of Mexico. Identifying the scale form and composition and the factors affecting its dissolution resulted in a treatment that successfully removed the scale, thereby enhancing gas production from the well.
This scale was identified as wurtzite, a form of zinc sulfide scale. Extensive laboratory testing considered acid solubility and other scale-removal issues at downhole temperature and pressure conditions, as compared with the theoretical solubility of zinc sulfide in hydrochloric acid (HCl). The study also determined that other factors may affect the real-world dissolution efficiency of the acid: pressure changes, hydrogen sulfide scavenger concentration and type, the ratio of acid volume to scale weight, pre-treatment oxidizer use, and pH values that prevent reprecipitation of dissolved scale.
This paper will describe the prejob testing process and a field case history of a coiled-tubing acid scale treatment that effectively removed the zinc sulfide scale from tubulars and the formation. Data will be presented showing the composition of the acid-flow-back samples as well as the treatment and production charts.