bluuebunny/crossref_metadata_2025 huggingface dataset:
An Educational Module to Explore what is the Role of an Electrolyte in an Electrochemical cell
Authors: Menéndez Christian , Díaz-Vázquez Liz , Mayol Ana-Rita , Cabrera Carlos R.
Published: November 2012

A general chemistry experiment has been adapted in which electrochemical principles in fuel cells are applied to the curriculum, thus bringing research into the classroom. It is well documented that students struggle in understanding redox reactions, in particular when applied to an electrochemical cell. There are three basic concepts needed to analyze these energy devices: anode, cathode and electrolyte.

In the proposed experiment, undergraduate students explored the role on an electrolyte in an electrochemical cell. Inquiry based methods were used to introduce the experiment. Explanations of fundamental electrochemical concepts involved in fuel cells were introduced to the students with pre- and post-laboratory activities and experimental results discussions. The lesson for the experiment “role of an electrolyte in an electrochemical cell” was planned to improve students’ technological skills and application of knowledge acquired in daily life. The battery was made using household materials: zinc, copper and napkin paper soaked in different electrolyte solutions. Students correlated the voltage of the cells with the substances being used in the experiment and classified these as strong electrolyte, weak electrolyte or non electrolyte. A variety of assessment tools were designed and incorporated during the experience to probe students understanding in the main topics and to identify the struggles during their learning process.
Consistent effects of productivity and disturbance on diversity between landscapes
Authors: Tonkin Jonathan D. , Death Russell G.
Published: November 2012

Productivity and disturbance have a strong role in determining diversity patterns in nature yet whether they operate individually or interact to determine diversity is unclear. Moreover, what effect land‐use change has on this relationship has not been assessed. We tested whether land use influenced the relationship between productivity, disturbance and diversity, and assessed the fit of three productivity‐disturbance‐diversity models, using data from multiple samplings of 16 streams in two contrasting regions of the North Island of New Zealand. As the Dynamic Equilibrium Model (DEM) has received inconsistent support in all ecosystems and little favorable applications in lotic systems, we applied this along with two previously developed for stream communities. Although the community structure differed between the two regions, the response of taxonomic richness to productivity and disturbance was consistent. That is, richness was log‐linearly related to productivity and declined monotonically with disturbance. However, there was no evidence of an interactive effect of productivity and disturbance. When accounting for density (rarefaction) the results were inconsistent, exhibiting no relationship with productivity but declining with disturbance. Our results suggest both the Death and Tonkin productivity‐disturbance‐diversity models are the most applicable in these communities where disturbance simply removes taxa and productivity controls the upper limit to richness.
Simulation of the Effect of Pressure and Solution Gas on Oil Recovery From Surfactant/Polymer Floods
Authors: Roshanfekr M. , Johns R. T. , Pope G. , Britton L. , Linnemeyer H. , Britton C. , Vyssotski A.
Published: November 2012

Surfactant/polymer (SP) and alkali/surfactant/polymer flooding is of current interest because of the need to recover residual oil after primary and secondary recovery. If designed properly, these enhanced-oil-recovery processes can give very high oil recoveries. Microemulsion phase behavior plays a central role in process performance and is typically measured by performing salinity scans in glass pipettes at atmospheric pressure and reservoir temperature using dead crude oil from the reservoir of interest. There have been only a few experiments reported in the literature on live oil at reservoir pressure and temperature, and the importance of those experimental results is conflicting.

This paper investigates the effect of pressure and solution gas on microemulsion phase behavior and its impact on oil recovery. We examine previous data reported in the literature, and report new measurements with live oil to show that the optimum parameters can change significantly. The experiments show that while pressure induces a phase transition from upper microemulsion (Winsor Type II+) to lower microemulsion (Winsor Type II—), solution gas does the opposite. An increase in pressure decreases the optimum solubilization ratio and shifts the optimum salinity to a larger value. Adding methane to dead oil at constant pressure does the reverse. Thus, these effects are coupled and both must be taken into account. Using a numerical simulator, we show that these changes in the optimum conditions can significantly impact oil recovery if not accounted for in the SP design.
Mechanical Interaction of Multiple Fractures—Exploring Impacts of the Selection of the Spacing/Number of Perforation Clusters on Horizontal Shale-Gas Wells
Authors: Cheng Y..
Published: November 2012

For multistage hydraulic fracturing of horizontal wells with cased-hole completion, multiple perforation clusters are used typically to create multiple fractures in any single stage. How to place these perforation clusters is a critical issue because the number of perforation clusters to be used and the space between them significantly impact how effectively the fractures can be created in the formation. To optimize the spacing of perforation clusters, stress distributions and fracture mechanics need to be well understood.

In this study, the displacement-discontinuity method is used to construct a boundary-element model, which is able to analyze the stress distributions around multiple transverse fractures and the geometries of those fractures. With the boundary-element model, multiple cases are investigated for a different number of fractures and fracture spacings. Changes of both minimum and maximum stresses and shear stress around these fractures are illustrated first. It is found that for the cases with more than two parallel fractures, there is a strong stress concentration around the center fractures. The calculated displacements indicate that the created fractures are no longer elliptic-like, and the widths of the center fractures are reduced significantly compared with those of a single fracture. For the case of two parallel fractures, the stress concentration between two fractures also results in asymmetrical fracture shape, but the fracture widths are not reduced significantly.

This study indicates that the number and spacing of the fractures need to be selected carefully to create effective fractures with appropriate fracture geometries. The boundary-element model provides a useful tool to relate rock geomechanic properties to stress distribution and fracture geometries for multiple fractures in hydraulic fracturing of horizontal wells, which can be used as a guide to space the perforation clusters.
2D Analytical Solution of Ideal Perforation Flow
Authors: Li B.. , Sun D.. , Gladkikh M.. , Wu J..
Published: November 2012

Core-flow efficiency (CFE) is defined to quantitatively evaluate the flow performance of single-shot perforation. To calculate CFE, the flow rate of the ideal perforation flow in the core target is needed. The ideal flow rate is typically calculated with numerical simulators, but the computation may be time consuming and costly.

This paper presents the 2D analytical solution of the steady-state flow model (mass-conservation equation) for an ideal singleshot perforation in a cylindrical core sample. The separation-of-variable method is used to solve the partial-differential equation (PDE) of the flow model. Pressure and velocity distributions in (r, z) space are obtained, along with the flow-rate distribution along the perforation tunnel.

The accuracy and convergence of the analytical solution for ideal single-shot perforation flow are investigated and compared with those of the numerical solution of the commercial software ANSYS Fluent (ANSYS Fluent 12.0 User's Guide 2001). The analytical solution for the governing equation of ideal perforation flow is composed of an infinite number of Bessel functions. To compute CFE by making use of this analytical solution, the analytical solution is approximated with a limited number of Bessel functions. The approximated analytical solution is analyzed and compared with the numerical solutions from ANSYS Fluent.

Further, the axial-, radial-, and radial/axial-flow geometries of an ideal single-shot perforation are characterized with their approximated analytical solutions. Interactions between the boundary condition, perforation parameters, and core parameters are investigated for these flow geometries.

The analysis results show that: (1) The analytical solution has no grid effects, (2) the boundary condition of the perforated core is the dominant factor in the ideal flow rate of the perforated core, and (3) the penetration depth and anisotropic permeability are the significant factors in the flow performance of the perforated core.
Applying Fractional-Flow Theory Under the Loss of Miscibility
Authors: Ghanbarnezhad-Moghanloo Rouzbeh , Lake Larry W.
Published: November 2012

This paper examines the limits of the Walsh and Lake (WL) method for predicting the displacement performance of solvent flood when miscibility is not achieved. Despite extensive research on the applications of fractional-flow theory, the prediction of flow performance under the loss of miscibility has not been investigated thoroughly.

We introduce the idea of an analogous first-contact miscible (FCM) flood to study miscibly degraded simultaneous water and gas (SWAG) displacements using the WL method. Furthermore, numerical simulation is used to validate the WL solution on one oil/solvent pair. In the simulations, the loss of miscibility (degradation) is attributed to either flow-associated dispersion or insufficient pressure to develop the miscibility.

1D SWAG injection simulations suggest that results of the WL method and the simulations are consistent when dispersion is limited. For the 2D displacements, the predicted optimal water-alternating-gas (WAG) ratio is accurate when the permeable medium is fairly homogeneous with a limited crossflow or is heterogeneous with a large lateral correlation length (the same size or greater than the interwell spacing).

The results suggest that the accuracy of the WL method improves as crossflow is reduced. In addition, linear growth of the mixing zone with time is observed in cases for which the predicted optimal WAG ratio is consistent with the simulation results. Hence, we conclude that the WL solution is accurate when the mixing zone grows linearly with time.
The Effects of Barium Sulfate Saturation Ratio, Calcium, and Magnesium on the Inhibition Efficiency—Part I: Phosphonate Scale Inhibitors
Authors: Shaw S.S.. S. , Sorbie K.S.. S. , Boak L.S.. S.
Published: November 2012

Conventional phosphonate-type scale inhibitors (SIs) are commonly applied for barite-scale prevention in oil fields. The barite forms when the injection water (IW), which is usually sulfate rich, is injected into a barium-containing formation water (FW). The inhibition efficiency (IE) of barite-scale inhibitors is affected by the barium sulfate saturation ratio (SR) of the brine mix and, additionally, by the presence of divalent cations Ca2+ and Mg2+. What is less well known is that the precise balance between these factors (SR and Ca2+/Mg2+ ratio) can vary significantly for different phosphonate species. This paper presents novel IE experimental results for phosphonate-scale inhibitors DETPMP and HMTPMP (penta-phosphonates), OMTHP (hexa-phosphonate), and HMDP (tetra-phosphonate). Minimum-inhibitor-concentration (MIC) levels for each SI are established by testing a wide range of brine IW/FW mixing ratios, which changes (i) barite SR and precipitated mass, (ii) molar ratio of Ca2+/Mg2+, and (iii) the ionic strength of the brine mix.

The phosphonate SIs were categorized into two types on the basis of their MIC-vs.-percent-North Sea-seawater (NSSW) behavior. Type 1 (e.g. DETPMP and OMTHP) are affected principally by SR and are rather less sensitive to Ca2+/Mg2+ ratio although they do show some sensitivity to the latter factor. Type 2 (e.g., HMTPMP and HMDP) are severely affected by brine Ca2+/Mg2+ ratio as well as SR. To demonstrate these effects conclusively, a series of IE experiments is presented with varying [Ca2+] and [Mg2+] (which normally occurs in the field as the IW/FW ratio changes over time) and then similar experiments are repeated at a fixed Ca2+/Mg2+ molar ratio. The MIC level measured for both types of phosphonate SI always correlates very well with the barite SR at fixed Ca2+/ Mg2+ molar ratio (fixed case). In addition, we find the MICs of both types of SI are much lower in the fixed-case experiments (higher Ca2+/Mg2+ molar ratio), compared with the base case, because of the beneficial effect of higher [Ca2+]. The effects observed are important for field application of phosphonate SIs because they show how the various species are sensitive to the changing scaling problems as the %NSSW increases, in terms of SR and Ca2+/Mg2+ molar ratio. These results also give some important insights into the mechanism by which different phosphonates actually work in inhibiting barite scale.
The Effects of Barium Sulfate Saturation Ratio, Calcium, and Magnesium on the Inhibition Efficiency—Part II: Polymeric Scale Inhibitors
Authors: Shaw S.S.. S. , Sorbie K.S.. S. , Boak L.S.. S.
Published: November 2012

In oilfield-produced waters, the barite mineral-scaling problem is a "moving target" because the seawater/formation-water (SW/ FW) mixing ratio is constantly changing. Therefore, the barite saturation ratio (SR), the yield of barite precipitate, and molar ratio Ca2+/Mg2+ in the produced waters are all evolving over time.

This paper describes the effects of SR and molar ratio Ca2+/ Mg2+ on the barium sulfate inhibition efficiency (IE) of nine polymeric scale inhibitors (SIs): phosphino poly carboxylic acid (PPCA); maleic acid ter-polymer (MAT)—a green SI; sulfonated PPCA (SPPCA); phosphino methylated polyamine (PMPA)—a poly-phosphonate; a generic P-functionalized copolymer (PFC); polyvinyl sulfonate (PVS); vinyl sulfonate acrylic acid copolymer (VS-Co); and cationic ter-polymers A and B (CTP-A and CTP-B). The behavior for polymers is compared with similar results for phosphonate SIs (Shaw et al. 2010). IE experiments were carried out for a wide range of SW/FW compositions (i.e., SR and molar ratio Ca2+/Mg2+ varying). The minimum-inhibitor-concentration (MIC) levels of these polymeric SIs sometimes correlate with the level of SR, but not always, which is because of Ca2+ and Mg2+ effects. When experiments were repeated but the produced-brine molar ratio Ca2+/Mg2+ was fixed, MICs always correlate with the level of SR for all nine polymers studied. However, it was observed that for SIs PPCA, MAT, and PFC, the base-case MICs (i.e., molar ratio Ca2+/Mg2+ varying) were less than the fixed-case MICs (molar ratio Ca2+/Mg2+ fixed), whereas in testing SPPCA, PMPA, PVS, VS-Co, and both the cationic terpolymers, the converse is true (i.e., the fixed-case MIC is less than the base-case MIC). It has been demonstrated conclusively that the high [Ca2+] in the fixed-case tests causes some SI precipitation with brine Ca2+ when PPCA is being evaluated (as PPCA-Ca). Sulfonate functional groups present on polymeric SI molecules may help to prevent such incompatibility problems encountered with brine Ca2+ (e.g., SPPCA does not precipitate as SPPCA-Ca). Low levels of brine calcium (e.g., approximately 500 to 700 ppm) can be very beneficial to the IE performance of PPCA. However, when the [Ca2+] reaches a certain level (approximately 1,000 ppm or higher), this causes some precipitation of a Ca–PPCA compound. It has been illustrated that low-to-moderate Ca2+ levels are often best, and it is concluded that this is why SIs PPCA, MAT, and PFC perform better under base-case experimental conditions (lower Ca2+ mix). It has been illustrated that PMPA behaves remarkably similarly to conventional phosphonate SIs with regard to Ca2+ and Mg2+. In fact, the behavior of PMPA suggests that it is not polymeric in nature. PVS, VS-Co, and both the cationic ter-polymers are mildly affected by divalent ions Ca2+ and Mg2+, with the latter being affected more than PVS because of the presence of carboxylate functional groups.
Scale Prediction for Oil and Gas Production
Authors: Kan Amy T. , Tomson Mason B.
Published: November 2012

Scale 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

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

Deconvolution 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

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

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

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

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

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

Tests 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

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 <1, 1, and >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

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.
The Modification of the Dykstra-Parsons Method for Inclined Stratified Reservoirs
Authors: El-Khatib Noaman A.F.
Published: November 2012

The Dykstra-Parsons method (Dykstra and Parsons 1950) is used to predict the performance of waterflooding in noncommunicating stratified reservoirs. Much interest has been shown recently in the application of the method to chemical flooding, particularly for the case of polymer injection used for mobility control. The original method assumes that the reservoir layers are horizontal; however, most oil reservoirs exhibit a dip angle, with water being injected in the updip direction. Therefore, it is important to account for the effect of inclination on the performance of the method.

A modification of the Dykstra-Parsons equations is obtained to account for reservoir inclination. The developed model includes a dimensionless gravity number that accounts for the effect of the dip angle and the density difference between the displacing and displaced fluids. The derived equation that governs the relative locations of the displacement fronts in different layers is nonlinear, includes a logarithmic term, and requires an iterative numerical solution. This solution is used to estimate the fractional oil recovery, the water cut, the injected pore volume, and the injectivity ratio at the time of water breakthrough in successive layers.

Solutions for stratified systems with log-normal permeability distribution were obtained and compared with horizontal systems. The effects of the gravity number, the mobility ratio, and the Dykstra-Parsons permeability-variation coefficient (VDP) on the performance were investigated. Cases of updip and downdip injection are discussed.

It was found that for a positive gravity number (updip water injection), performance is enhanced in terms of delayed water breakthrough, increased fractional oil recovery, and decreased water cut as compared with horizontal layers. This occurs for both favorable and unfavorable mobility ratios but is more evident in unfavorable mobility ratios and more-heterogeneous cases. For the case of a negative gravity number (downdip water injection or updip gas injection), the opposite behavior was observed.

The results were also compared with the performance of inclined communicating reservoirs with complete crossflow. The effect of communication between layers was found to improve fractional oil recovery for favorable and unit mobility ratios and decrease recovery for unfavorable mobility ratio.
Numerical Studies on Two-Way Coupled Fluid Flow and Geomechanics in Hydrate Deposits
Authors: Kim J.. , Moridis G.J.. J. , Yang D.. , Rutqvist J..
Published: November 2012

Coupled flow and geomechanics play an important role in the analysis of gas-hydrate reservoirs under production. The stiffness of the rock skeleton and the deformation of the reservoir, as well as porosity and permeability, are directly influenced by (and interrelated with) changes in pressure and temperature and in fluid-(water and gas) and solid-(hydrate and ice) phase saturations. Fluid and solid phases may coexist, which, coupled with steep temperature and pressure gradients, result in strong nonlinearities in the coupled flow and mechanics processes, making the description of system behavior in dissociating hydrate deposits exceptionally complicated.

In previous studies, the geological stability of hydrate-bearing sediments was investigated using one-way coupled analysis, in which the changes in fluid properties affect mechanics within the gas-hydrate reservoirs, but with no feedback from geomechanics to fluid flow. In this paper, we develop and test a rigorous twoway coupling between fluid flow and geomechanics, in which the solutions from mechanics are reflected in the solution of the flow problem through the adjustment of affected hydraulic properties. We employ the fixed-stress split method, which results in a convergent sequential implicit scheme.

In this study of several hydrate-reservoir cases, we find noticeable differences between the results from one- and two-way couplings. The nature of the elliptic boundary value problem of quasistatic mechanics results in instantaneous compaction or dilation over the domain through loading from reservoir-fluid production. This induces a pressure rise or drop at early times (low-pressure diffusion), and consequently changes the effective stress instantaneously, possibly causing geological instability. Additionally, the pressure and temperature regime affects the various phase saturations, the rock stiffness, porosity, and permeability, thus affecting the fluid-flow regime. These changes are not captured accurately by the simpler one-way coupling. The tightly coupled sequential approach we propose provides a rigorous, twoway coupling model that captures the interrelationship between geomechanical and flow properties and processes, accurately describes the system behavior, and can be readily applied to large-scale problems of hydrate behavior in geologic media.
Combining the Ensemble Kalman Filter With Markov Chain Monte Carlo for Improved History Matching and Uncertainty Characterization
Authors: Emerick A.A.. A. , Reynolds A.C.. C.
Published: November 2012

It is well known that when applied to reservoir history-matching problems, the ensemble Kalman filter (EnKF) can lead to a large underestimation of uncertainty in the posterior probability-density function (PDF) for reservoir-model parameters. Here, we demonstrate that, regardless of whether covariance localization is used, EnKF also can lead to an overestimation of the uncertainty in future predictions of reservoir performance. This overestimation occurs because, even though the data matches obtained with EnKF tend to appear reasonable, these matches are significantly worse than those that can be obtained when history matching dynamic data with a gradient-based method. The relatively poor data match obtained with EnKF means that the ensemble of states generated by assimilating data with EnKF are of relatively low probability (low value of posterior PDF). Under reasonable assumptions, a Markov Chain Monte Carlo (MCMC) algorithm will theoretically generate an accurate sampling of the posterior PDF conditional to dynamic data. However, standard implementations of MCMC are not computationally feasible because each proposed state in the chain requires a run of the forward model (reservoir simulator). In this work, the EnKF and MCMC methodologies are combined to obtain a relatively efficient algorithm for sampling the posterior PDF for reservoir-model parameters. In this algorithm, a symmetric square root of the state vector's posterior covariance matrix is calculated from an ensemble of state vectors obtained from EnKF. It is shown that this square root can be used both to propose new states in the Markov chain and to evaluate the probability of accepting the state without running the simulator, which results in an efficient algorithm. In order to improve sampling, we also propose to generate multiple ensembles with EnKF and multiple Markov chains, which are then combined and resampled based on the normalized objective function. We tested the proposed EnKF-MCMC algorithm on a small 3D two-phase-flow reservoir example. The problem is sufficiently small that by using MCMC only, we are able to generate a long chain based on 2 million proposed states. The posterior PDF calculated from this long chain is assumed to be accurate. The posterior PDFs for predicted cumulative oil and water production generated with the new EnKF-MCMC algorithm provide results that are in reasonable agreement with the posterior PDFs for the cumulative oil and water production obtained from the long Markov chain, whereas the corresponding PDFs obtained using EnKF with and without covariance localization exhibit a significantly higher variance (i.e., overestimate uncertainty in the predicted cumulative reservoir production).