bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Conceptual Study of Finger-Type Slug Catcher for Heavy-Oil Fields
Authors: Márquez J.. , Manzanilla C.. , Trujillo J.. 
Published: October 2010

Summary
The gas/liquid-separation processes in heavy- and extra-heavy-oil fields are performed mainly with gravity conventional separators. However, the separation efficiency of this equipment depends on the operating conditions, an appropriate design, and the properties of the fluids. Therefore, the separation efficiency is affected mainly by the high liquid viscosity, low pressures, and the low gas-flow rate that are present in heavy- and extra-heavy-oil fields. Additionally, these conditions increase the probability of slug-flow formation through pipelines, which causes operational problems, mainly in the separation process.
This situation raises the need to design a gas/liquid separator able to handle viscous liquid, reduce the effects of slug flow, and perform an efficient separation. There are different technologies that can help improve gas/liquid separation, among them the finger-type slug catcher. This technology is usually used in gas fields or light- and medium-oil fields as a flow conditioner and slug-flow mitigator. However, this paper has changed that focus toward considering a heavy-oil design.
This paper presents an improvement in the methodology of Sarica et al. (1990), predicting the dimensions of a finger-type slug catcher for heavy-oil fields. It is derived from the effect from the transition of stratified flow to nonstratified flow when the liquid phase is viscous and only considers slug-flow characteristics under normal flow; on the basis of the improvement, the required diameter and length of the finger are determined.
This improvement is used to design a finger-type slug catcher for heavy-oil fields in the Orinoco belt. An economic comparison against conventional separators is presented, demonstrating the finger-type slug catcher to be more economical than the conventional separator.
Upscaling of Miscible Floods in Heterogeneous Reservoirs Considering Reservoir Mixing
Authors: Garmeh Gholamreza , Johns Russell T. 
Published: October 2010

Summary
Inaccurate modeling of reservoir mixing by using large gridblocks in compositional simulation can affect recoveries significantly in miscible gasfloods and lead to inaccurate predictions of recovery performance. Reservoir mixing or dispersion is caused by diffusion of particles across streamlines; mixing can be enhanced significantly if the surface area of contact between the reservoir and injected fluid is increased as fluids propagate through the reservoir. A common way to convert geological models into simulation models is to upscale permeabilities on the basis of reservoir heterogeneity. Upscaling affects the degree of mixing that is modeled, but the importance of reservoir mixing in upscaling is largely ignored. This paper shows how to estimate the level of mixing in a reservoir and how to incorporate mixing into the upscaling procedure.
We derive the key scaling groups for first-contact miscible (FCM) flow and show how they have an impact on reservoir mixing. Heterogeneities are assumed to dominate the flow regime so that gravity effects are negligible. We examine only local mixing, not apparent mixing caused by variations in streamline path lengths (convective spreading). Local mixing is important because it affects the strength of the injected fluid and can cause an otherwise multicontact miscible (MCM) flood to become immiscible. More than 1,000 2D numerical simulations are carried out using experimental design to estimate dispersivity as a function of the derived scaling groups.
We show that reservoir mixing is enhanced owing to fluid propagation through heterogeneous media. Because mixing is dependent on heterogeneities, upscaling is an iterative process in which the level of mixing in both the longitudinal and transverse directions must be matched from the fine to the coarse scale. The most important groups that affect mixing are the mobility ratio, dispersion number, correlation lengths, and the Dykstra-Parson coefficient. Large dispersion numbers yield greater dispersivities away from the injection well. We show through simulations of both FCM and MCM floods that gridblock size can be increased significantly when reservoir mixing is large. Heterogeneous reservoirs with large longitudinal correlation lengths can be upscaled to larger gridblocks than reservoirs with random permeability fields. This paper shows how to determine a priori the maximum gridblock size allowed in both the x- and z-directions to predict the oil recovery from miscible gasfloods accurately.
Application of After-Closure Analysis to a Dual-Porosity Formation, to CBM, and to a Fractured Horizontal Well
Authors: Soliman M.Y.. Y. , Miranda Carlos , Wang Hong Max 
Published: October 2010

SummaryPublished techniques for after-closure analysis of fracturing data usually assume the presence of a vertical fracture intersecting a vertical well. In addition, these published techniques usually assume that the formation is homogeneous. When the formation is naturally fractured or the well is horizontally intersecting a transverse vertical fracture, those assumptions are obviously violated and the published analysis techniques might not be applicable. Through the use of analytical and numerical solutions and application to actual field data, this paper investigates the analysis of after-closure data for heterogeneous formations, a naturally fractured formation, a CBM, and a fractured horizontal well.This paper briefly reviews the various available techniques for after-closure analysis, pointing out the strengths and weaknesses of each. An analytical solution for an injection-falloff test for a naturally fractured formation has been developed and is presented. This solution might be used to analyze data for a minifrac test in a naturally fractured formation where the fracture has healed. Numerical simulation validated the developed solution for a fracture that has healed. The same numerical simulator was used to expand the solution to a situation where the fracture maintains residual conductivity.The solution for a minifrac test in the case of a transverse fracture is also presented and discussed. Using a numerical simulator, minifrac tests are simulated and analyzed for both heterogeneous formations and fractured horizontal wells. Guidelines for the analysis of such data have been developed and presented.Field data are also presented. One case presents a minifrac test for a heterogeneous formation. A case for a transverse fracture intersecting a horizontal well is also presented and analyzed. A third case for CBM is discussed.
MEOR Success in Southern Saskatchewan
Authors: Town K.. , Sheehy A.J.. J. , Govreau B.R.. R. 
Published: October 2010

Summary
A microbial enhanced-oil-recovery (MEOR) process was successfully applied in a mature waterflooded reservoir in Saskatchewan, Canada. A nutrient solution, which was designed specifically for this reservoir to stimulate indigenous microbes to grow, multiply, and help to release oil, was tested and piloted. A significant decrease in water cut and increase in oil production have been realized through the selective stimulation of bacteria using nutrient injection.
The field is a mature waterflood averaging more than 95% water cut. To combat the increasing water-cut issue, an in-situ microbial response analysis (ISMRA) was performed on a typical high-water-cut producer in the area. The test well was treated with a nutrient solution and then was shut in for a number of days to allow indigenous microbes to grow and multiply. Upon return to production, the well produced at an average of 200% more oil with a 10% decrease in water cut for a year. Pretreatment rates averaged 1.2 m3/d of oil (8 BOPD) and post-ISMRA treatment daily production peaked at 4.1 m3/d of oil (26 BOPD). The ISMRA provides a direct support of laboratory studies and frequently increases oil production.
As a result of the successful ISMRA, a pilot project was initiated and the nutrients were applied in three batch treatments on an injector with three offset production wells. Three weeks after the first batch treatment, a water-cut decrease was seen at one of the offset producers. This well's oil production gradually increased from 1.4 to more than 8 m3/d (9 to 50 B/D). Oil production in another producer doubled from 1.5 to more than 3.0 m3/d (9 to 19 B/D). Subsequent treatments were tried on marginally economic wells and on a reactivated idle producer. The average decrease in water cut in these wells was more than 10%. On the idle well, oil production increased from 0.5 m3/d (3 B/D) pretreatment to an average of 3.0 m3/d (19 B/D) post-treatment.
Throughout the world, there remains a huge target for enhanced-oil-recovery (EOR) processes to target (Bryant 1991). This successful MEOR application will have a tremendous impact on ultimate recovery in many of these reservoirs not only through an increase in production, but a decrease in operating costs through associated reduction in lifting costs with less water production.
Comprehensive Model for Flow Behavior of High-Performance-Fracture Completions
Authors: Zhang Y.. , Marongiu-Porcu M.. , Ehlig-Economides C.A.. A. , Tosic S.. , Economides M.J.. J. 
Published: October 2010

Summary
Experience shows that high-performance fractures (HPFs) may retain near-unit-flow efficiency (equivalent to zero skin in a vertical well) and rarely fail, even in highly deviated wells. This may be partly because overly simplistic models of the well flow behavior lead operators to maintain wells at lower production rates than could have been achieved for the same amount of injected proppant with a vertical-well-completion design. Rigorous models that account for widely accepted rock-mechanics fundamentals indicate that the fracture-to-well connection is compromised in deviated wells and lead to questions concerning whether the bulk of the flow to the well actually passes through the fracture.
Distributed volumetric sources are used in this model to rigorously model a wide variety of possible fracture geometries such as an expanded wellbore because of halo effect, flow strictly through the fracture, and combined flow through a single fracture and to remaining flowing perforations not connected to the fracture. The model also includes turbulent-flow effects that may occur for radial-flow conditions in the fracture plane or in the reservoir opposite wellbore sections not connected to the fracture, along with high-velocity flow through the perforation tunnels. It also computes the effective flow area at the resulting face between the reservoir and the completion to check whether flow velocity exceeds conditions that would risk production of reservoir fines, and it estimates the screen-flow velocity on the basis of the number of flowing perforations.
This comprehensive view of the HPF completion enables a thorough analysis of the risks of flowing the well at high rate. Field examples show that the new model depicts real field conditions in calculating the total skin, flow fractions, and the flux for HPF completions in high-rate gas and oil wells.
Complete inflow-performance behavior for likely flow patterns for HPF wells in oil and gas reservoirs is provided.
A Practical Method for Minimum-Miscibility-Pressure Estimation of Contaminated CO2 Mixtures
Authors: Johns R.T.. T. , Ahmadi Kaveh , Zhou D.. , Yan M.. 
Published: October 2010

Summary
Minimum miscibility pressure (MMP) is a key parameter in the design of gasfloods. Injection-gas compositions often vary during the life of a gasflood owing to reinjection and mixing of fluids in situ. Understanding the impact of the gas compositional changes on the MMP is essential to optimal design of fieldwide pressure management and carbon dioxide (CO2) use. Determining the MMP by slimtube or other methods for each possible variation in the gas-mixture composition is impractical. This paper gives an easy and accurate way to determine impure CO2 MMPs for variable field solvent compositions on the basis of just a few MMPs. Alternatively, the approach could be used to estimate the enrichment level required to lower the MMP to a desired pressure.
The MMP-estimation method relies on determining the MMP for pure CO2 injection, and also for a few impure binary MMPs at small CO2-contaminant levels. The number of MMPs needed for the method is equal to the number of components in the injection gas. We use the method of characteristics (MOC) and our newly developed mixing-cell method to estimate the required MMPs, although any reliable MMP analytical or experimental method can be used. We demonstrate how to calculate MMPs for several multicomponent oils displaced by CO2 contaminated by mixtures of N2, CH4, C2, C3, and H2S. The results show that the predicted MMPs for a west Texas crude displaced by contaminated-CO2 injection streams are nearly linear over the range from pure-CO2 injection to any mole fraction combination of the five contaminants. The accuracy of the predicted MMPs is within ±15 psia of that from calculations using mixing-cell simulations, slimtube simulations, and slimtube experiments where available. For another example oil displacement by impure CO2, however, the linear trend in MMPs with contamination mole fractions is accurate only for total contamination levels less than approximately 20% mole fraction, but this is still within a useful range for CO2-gasflood design and optimization. We also examine the sensitivity of local displacement efficiency to dispersion for binary gas mixtures using 1D simulation.
A Crosslinkable Synthetic-Polymer System for High-Temperature Hydraulic-Fracturing Applications
Authors: Holtsclaw Jeremy , Funkhouser Gary P. 
Published: October 2010

Summary
A new hydraulic-fracturing fluid has been developed that is capable of reaching fluid service temperatures up to 232°C. This fracturing fluid technology uses a synthetic polymer that is crosslinkable with metal ions to generate high viscosity. The synthetic-polymeric fracturing gel overcomes the thermal limitations of traditional guar and derivatized guar-based fracturing fluids. Several advancements have been made in the development of this technology to maximize the efficiency of crosslinking and to give an effective breaking profile, resulting in good laboratory gel cleanup in the proppant pack. Research efforts have yielded a fracturing fluid with good fluid stability at high temperatures to create better proppant transport and placement in these most-demanding environments.
An integral part of this fluid is a crosslinking system that can be "tuned" for crosslinking onset from 38 to 138°C, allowing for optimization for particular well conditions. The crosslinking system allows the treatment schedule to be tailored to the targeted well to help minimize frictional pressure loss. An efficient and effective oxidative-breaker package has been developed to give a controlled rheological break for the synthetic fluid and provide good regained conductivity data. The new, high-temperature fracturing technology provides a new tool to stimulate hotter, deeper hydrocarbon resources to help maximize hydrocarbon recovery. This fracturing-fluid system has been applied successfully in south Texas at temperatures approaching 232°C.
Laboratory rheological data that demonstrate fluid stability, crosslinking performance, and controlled fluid breaks are presented. Dynamic fluid-loss and regained-conductivity data are also presented to illustrate fluid cleanup in proppant packs.
Gas-Reserves Estimation in Resource Plays
Authors: Lee John , Sidle Rod 
Published: October 2010

SummaryThe petroleum industry's lack of understanding of physical properties and the physics controlling production from many important resource plays limits its ability to model and forecast with confidence production and reserves from these resources in many cases. While measurement technology and modeling accuracy is improving, the industry is often forced to resort to empirical methods that lack the usual validation required for high confidence in results. This paper analyzes some of the procedures in common use for forecasting and identifies some limitations in the techniques. Advances in the industry's ability to forecast future production (and thus estimate reserves) more accurately in resource plays will impact financial forecasts, perceived asset values, and accuracy of reserves disclosed to the public.
New Developments in the Analysis of Scale Inhibitors
Authors: Boak L.S.. S. , Sorbie K.S.. S. 
Published: October 2010

Summary
Scale inhibitors (SIs) are used to control oilfield scale formation, and the ability to analyze these species is very important such that SI concentrations as low as 0.5-ppm active need to be measured accurately. If phosphorus is present in the SI molecule, then inductively-coupled-plasma (ICP) -based methods may be used for analysis. However, the oil industry's increasing requirement to be environmentally friendly means that polymeric "green" SIs are now being used more, which raises issues concerning detection techniques (i.e., ICP vs. wet-chemical techniques). ICP detection for SIs is generally easier, but if it cannot be used, then at least time-saving improvements to wet-chemical techniques are extremely beneficial.
In this paper, analytical approaches are described that have been used recently to improve chemical SI assay, especially at low near-threshold levels (a few ppm active of SI). Progress is reported in five areas of SI analysis: Assay of sulfonated copolymer (VS-Co) was not possible by straightforward analysis without extensive dialysis and sample preparation. However, calibrations and repeats of accuracy similar to that of the C18 were found for VS-Co using amino-propyl (NH2) cartridges and the Hyamine method.The Oasis® 2×4 method has been applied to SI analysis, and this is able to assay all types of polymeric SIs in principle. This method has been used to detect a VS-Co SI in a wide variety of different brine salinities from distilled water (DW) to high-salinity formation waters (FW) (e.g., a Heron-type FW). Although achievable under these different conditions, there was a significant decrease in the absorbance signals recorded with increasing salinity that was not significantly improved by a higher-capacity sorbent cartridge.Various elements have been assayed in the oil phase using the ICP method. Calibrations and accurate repeats within 5 to 10% error were achieved. After solving compatibility issues, the concentration of an oil-tolerant SI was determined successfully using calibrations and accurate repeats over a range of 0 to 10 ppm and 0 to 2,500 ppm active SI.A matrix-matching Hyamine technique has been developed that allows any chloride-ion effects on the chelating process between the Hyamine and SI to be negated, allowing accurate analysis of low-polymeric SI concentrations.ICP and wet-chemical techniques have been able to accurately detect a P-tagged (phosphorus-tagged) copolymer-type SI. The ability to apply two independent analytical methods to a given species offers some important advantages when more than one SI is deployed in a field system. In this work, excellent correlation is observed between the wet-chemical and ICP assay methods for this P-tagged SI.
This study updates and adds to the set of analytical methods and procedures reported for SI analysis almost 20 years ago (Graham et al. 1993, 1995a, 1995b, 1996; Sorbie et al. 1992) and are described in our Flow Assurance and Scale Team (FAST) laboratory procedures manual (Sorbie and Boak 2006).
A Dynamic Simulation Study of Water Hammer for Offshore Injection Wells To Provide Operation Guidelines
Authors: Tang Yula , Ouyang Liang-Biao 
Published: October 2010

Summary
In water injectors, rapid shut-in creates a water hammer. Water-hammer effects resulting from the shutting in of water-injection wells have a considerable impact on injection-well performance and longevity. Over time, injectors that undergo repeated rapid shut-ins often have significantly reduced injectivity and show evidence of sanding and even failure of the downhole completion. This study seeks to provide an operational reference for the well-injection operation and valve installation to mitigate backflow and maintain the downhole- sand-control-device integrity and thus good water injectivity.
Two different shut-in scenarios for an offshore injection system have been investigated. One of the scenarios is that two wells are shut in and the third well is kept open. The other scenario is that the topside pump is stopped while the injection wells are still kept open. Water-hammer sensitivity on different parameters, such as valve-installation position, stroke time, water-backflow conditions, and the hydraulic characteristics, has been performed.
For Scenario I, the pressure change because of the wellhead shut-in is approximately 200 psi at bottomhole, which is much lower than the amplitude seen at the wellhead (3,400 psi). The third well, which stays open for injection, experiences an even larger pressure surge (approximately 450 psi at bottomhole). Backflow for the opening well could be close to 10,000 STB/D. With increasing skin because of cumulative injectivity damage by water-particle plugging and thermal-induced fracture closure at shut-in, the water-hammer-pressure fluctuation can be as high as 1,200 psi. For Scenario II, pressure fluctuation because of topside shut-in is 300 psi. With the surface-controlled subsurface safety valve (SCSSV) closing when backflow is felt, the water-hammer fluctuation can be reduced to 200 psi.
Unlike the classic water hammer in pipelines, water hammer in injection wells is much less in surge amplitude because the high-injectivity reservoir behaves like a cushion to absorb the water-hammer impact on the downhole completion and sandcontrol infrastructure. Water hammer in the wells and pipeline system experiences (1) after-flow with reduced bottomhole pressure (BHP) and flow rate into formation, (2) backflow when BHP becomes less than reservoir pressure, and (3) resumption of water flow into reservoir when BHP starts to increase. This cyclic process continues with reduced amplitude in each cycle because of friction. A check valve set at the bottomhole could stop the backflow in less than 1 second. This study provides useful reference and operation guidelines on offshore water-injection and completion design consideration.
An Evaluation of Microseismic Monitoring of Lenticular Tight-Sandstone Stimulations
Authors: Warpinski N.R.. R. , Waltman C.K.. K. , Weijers L.. 
Published: October 2010

SummaryMicroseismic monitoring in lenticular tight gas formations has a number of challenging issues associated with both analysis and interpretation. The heterogeneous nature of the reservoir and the typically small microseismic-event amplitudes make it essential to understand the limits of interpretation that should be applied in these reservoirs. With proper care, fracture lengths and azimuth, along with zonal coverage, are readily obtainable. However, fracture-height growth in these complex reservoirs needs to be assessed carefully. Microseismic data provide a level of self-quality-control potential through the use of a magnitude/distance assessment to guide interpretation and design. Hydraulic fractures observed in these reservoirs tend to be long, penetrating fractures that wander through the distributed/sand lenses, with modest height growth in most projects.