bluuebunny/crossref_metadata_2025_split huggingface dataset:
Impact of Fracture Growth on Well Injectivity and Reservoir Sweep during Waterflood and Chemical EOR Processes
Authors: Lee Kyunghaeng , Huh Chun , Sharma Mukul M. 
Published: October 2011

Abstract
During waterflooding, or chemical EOR processes with polymers, fractures are frequently generated in injectors. This can have a profound impact on the process performance and reservoir management. A fracture growth model was developed and linked to a reservoir simulator that incorporates the effect of (i) particle plugging due to filtration of solids and oil droplets in the injected fluids; (ii) non-Newtonian polymer rheology (shear-thinning and -thickening) for polymer injection; (iii) thermal stresses induced by cold water injection; and (iv) stress and fracture reorientation due to poroelastic effect and rock displacements near fractures. Dynamic fracture growth due to particle plugging, thermal stresses, and complex polymer rheology during chemical flooding, affects the well injectivity and reservoir sweep significantly. With the fracture growth model, simulations can be made not only to make more accurate reservoir sweep and oil recovery predictions, but also to help identify well patterns that may improve reservoir performance.
It is shown that both injected particles and polymers play an important role in fracture propagation. Oil recovery and reservoir sweep during the injection of water or polymer into a homogeneous reservoir is relatively unaffected by the propagation of an injection induced fracture. However, in multi-layered reservoirs, reservoir sweep and oil recovery are impacted significantly by a combination of particulate plugging, polymer rheology, thermal stresses, and fracture growth. The results of a dynamically growing fracture obtained from our fracture growth model differ substantially from the oil recovery obtained for a static fracture. The shear rate dependence of the polymer rheology is critical in determining the injectivity, fracture growth, and oil recovery.
Comparison of Multiphase Pumping Technologies for Subsea and Downhole Applications
Authors: Hua Gong , Falcone Gioia , Teodoriu Catalin , Morrison Gerald L. 
Published: October 2011

Abstract
The selection criteria for multiphase boosting options remain somewhat subjective and frequently influenced by the vendors’ data, which may mask potential limitations of this emerging technology. Existing literature on multiphase pumping tends to focus on a certain pump type for a specific field application, but does not provide more generalized criteria for the selection of multiphase boosting solutions from among those available in the market. A comprehensive literature review into the working principles of the major pump types identified the intrinsic advantages and limitations of each technology for subsea and downhole applications.
The survey showed that, for subsea application, both the twin-screw pump (TSP) and the helico-axial pump (HAP) can handle high suction gas volume fraction (GVF) with a fluid recycling system, or flow mixer. Thus, GVF is not a discriminating factor. The positive displacement principle allows TSPs to work with very low suction pressure, but limits their operating range because of the dependency of flowrate on their relatively low speed. However, these pumps can handle highly viscous fluid. The roto-dynamic concept enables the differential pressure of HAPs to self-adjust to any instantaneous change in suction GVF, and to achieve higher flowrate if sufficient suction pressure is maintained. As HAPs usually run at higher speed, they offer a wider operating range.
For subsea application, HAPs appear to be a better option than TSPs, because they offer higher operation flexibility and have a better installation track record.
For downhole applications, the electric submersible pump (ESP) and the progressing cavity pump (PCP) are the outstanding favorites, with the latter being preferred for lifting streams that are viscous or with high sand content. For GVF up to 70%, the roto-dynamic pump (RDP) is becoming a popular solution. Although it is claimed that the downhole twin-screw pump (DTSP) can handle up to 98% GVF, it is not yet widely accepted in the field.
Correlation of Surfactant-Induced Flow Behavior Modification in Gas Condensate Reservoirs with Dynamic Contact Angles and Spreading
Authors: Zheng Y. , Saikia B. , Rao D. N. 
Published: October 2011

Abstract
The commonly encountered condensate blockage problem causes severe impairment of gas productivity as the flowing bottom-hole pressure falls below the dew point in gas condensate reservoirs. This study investigates the potential for improving gas relative permeability and enhancing oil (condensate) recovery by using low-cost surfactants to alter wettability in the near wellbore region as well as fluid-fluid spreading coefficient. Surfactant-induced wettability alterations have been derived from experimental measurements of dynamic contact angles and oil-water relative permeabilities.
Coreflood experiments were conducted using two different rock-fluids systems: (1) Berea sandstone, condensate, synthetic brine and nitrogen; and (2) Parker sandstone, artificial retrograde gas, and synthetic brine at elevated pressures. The anionic surfactant, which was more effective in our previous work, has been used in this coreflood study. Contact angles were measured on quartz surface using Dual-Drop-Dual-Crystal (DDDC) technique and spreading coefficient was determined through measuring interfacial tensions using pendent drop method by drop shape analysis technique. Oil-water relative permeabilities were generated by history matching condensate recovery and pressure drop data obtained from the coreflood experiments.
The shifts in oil-water relative permeability ratio curves indicated that the wettability of this Berea core-condensate-brine system altered to intermediate-wet induced by this anionic surfactant. The contact angle measurements for this system with surfactant also substantiated the wettability alterations to intermediate-wet. The results of subsequent gasflood using nitrogen showed 82% improvement in gas relative permeability for this system. Positive spreading coefficient obtained in all Berea core cases indicates that it has less influence on enhanced gas relative permeability compared to wettability alteration. Corefloods using artificially prepared retrograde gas mixture creating in-situ retrograde gas condensation within the core system also showed the improvement in gas relative permeability. This study thus demonstrates that surfactant-induced alteration of wettability and spreading coefficient have the benefits for improving gas and condensate production by mitigating the condensate blockage problem.
Field Development Optimization Under Uncertainty: Screening-Models for Decision Making
Authors: Ogunyomi B. A. , Jablonowski C. J. , Lake Larry W. 
Published: October 2011

Abstract
In this study we develop an integrated asset model (IAM) for a greenfield offshore oil development and demonstrate its use in an uncertainty analysis workflow. The proposed framework enables a systematic quantification of the uncertainties and provides users with an in-depth understanding of the impact of uncertainties on major design and operational decisions. The IAM is specified for a hypothetical deepwater field to investigate three decisions: optimal initial facility capacity, optimal number of pre-drilled wells, and the optimal number of drilling rigs. The uncertainty analysis addresses two critical variables: reservoir thickness and the transmissibility between the reservoir compartments.
This work develops and demonstrates a fast-solving physics-based integrated optimization model where production, drilling, and facility expansion decisions are endogenous (that is, the model solves for these variables implicitly) and thus provides higher quality (and faster) guidance in many cases than the design-of-experiments and response surface workflows currently being used in the oil and gas industry.
Experimental and Modeling Study of Vapor-Liquid Equilibrium for Propane-Heavy Crude Systems at High Temperature Conditions
Authors: Kariznovi Mohammad , Nourozieh Hossein , Abedi Jalal 
Published: October 2011

Abstract
Heavy oil and extra heavy oil reserves have attracted increasing attention in recent years as alternatives to conventional oil reservoirs. Different technologies, such as vapor extraction and steam-assisted gravity drainage, have been developed for in situ extraction of these resources. It was recently found that the compounded effects of solvents and heat on the viscosity of heavy oil can provide oil production rates that may be equivalent to or higher than those from the injection of steam alone. In addition, this improved recovery product is complemented by a process that uses less fresh water and has lower greenhouse gas emissions.
There is, however, a distinct lack of basic data and mechanistic knowledge relevant to the solvent/heat-assisted recovery processes. Even the most fundamental experimental data, such as the solubility of commonly used solvents in oil, are not available. The quantitative effects of solvent on oil viscosity and phase behaviors at temperatures approaching the conditions of the in situ steam processes are also not well understood.
In the present study, the solubility of propane in an extra heavy oil and the saturated phase densities and viscosities were measured for temperatures from 100°C to 200°C at different pressures. These temperatures and pressures approach the conditions of the in situ steam processes in which both solvent and steam contribute to a higher reduction of oil viscosity.
The experimental results showed that, at high temperatures, the saturated phase viscosities converged as the pressure increased. In addition, the density data demonstrated crossover at an intermediate pressure for different temperatures. The data on the solubility and the physical properties can be utilized for the optimization of solvent/heat-assisted recovery processes. The observed phase behavior was modeled using an equation of state model, closely matching the experimental results. Such a model will be useful in the development of solvent/heat-assisted-recovery processes.
Perforating High-Pressure Deepwater Wells in the Gulf of Mexico
Authors: Baumann Carlos , Williams Harvey , Korf Timothy , Pourciau Robert 
Published: October 2011

Abstract
A large number of well perforation jobs are conducted successfully worldwide each year. However, gunshock related damage poses a significant risk when perforating high-pressure wells. This paper presents gunshock studies done with a simulation tool specifically developed to predict perforating gunshock loads and the associated structural loads on the equipment. This simulation effort includes results from seventeen Tubing Conveyed Perforating (TCP) jobs on high-pressure deepwater wells, with pressures ranging from 13,800 psi to the highest pressure wells ever perforated in the Gulf of Mexico at 20,700 psi. The results show very good agreement between software predictions and actual field data.
When planning perforating operations in high-pressure wells, engineers strive to minimize the risk of equipment damage from perforating gunshock loads, such as bent tubing and damage to packers. The risk of equipment damage from perforating gunshock loads increases very rapidly as the bottomhole pressure increases beyond 15,000 psi. The simulation tool used to perform gunshock studies is fast and can reliably identify perforating jobs that have a high possibility of gunshock related damage. For those cases where the chance of gunshock damage is high, design changes can be implemented to reduce or eliminate those potential risks.
In this review, computational predictions are compared with high-speed pressure gauge data, with the residual deformation of shock absorbers, and with high speed acceleration data. Fast gauge pressure data shows that predicted wellbore pressure transients are sufficiently accurate in magnitude and time. Peak pressure amplitudes measured at the gauges are, on average, within 8 percent of the predicted values. Residual deformations of shock absorbers correlate favorably with predicted peak axial loads, and available fast gauge acceleration data shows that the asymptotic gunstring acceleration is well predicted, both in amplitude and frequency. The ability to identify and reduce risks in perforating operations is important because the value of deepwater wells is very high and rig time losses are costly. With the software tool presented in this paper, engineers can optimize high-pressure well perforation designs in order to minimize the likelihood of gunshock related damage and the associated rig time losses.
Monitoring and Improving Water Injection Efficiency in a Structurally Complex Field
Authors: Rotondi M. , Binda A. , Draoui M. , Tsoumou A. , Tealdi L. 
Published: October 2011

Abstract
Understanding and capturing water influx behavior is crucial for correct reservoir management. Water injection efficiency is highly influenced by fault pattern, transmissibility and juxtapositions and petrophysical characteristics. Both structural and stratigraphic sequences could create permeability barriers, compartmentalization or thief zones that may lead to un-optimized injector placement and poor sweep efficiency. The field described in this paper is a pre-salt anticlinal structure filled with light oil. The formation is highly heterogeneous and characterized by complex syn-rift fault pattern that control the sedimentation and the basin topography. More than 30 different fluid contacts were observed. A lateral, weak and disconnected aquifer is present only in some peripheral of the field and the primary drive mechanism is mainly solution gas expansion. Dispersed water injection was seen as a solution to maintain reservoir pressure. Well production behaviour soon confirmed that the field is highly compartmentalised. Therefore an effort was made to capture this compartmentalisation by simultaneously integrating available static and dynamic data as seismic, wireline logs, PVT, MDT, well test and productions. Once every block was identified and injector wells drilled, basic material balance analysis was carried out to inject at voidage replacement. Tracer injection and salinity monitoring of produced water are used as useful indicators of water paths into the reservoir. On the other hand injectivity tests, fall offs and PLTs are performed to monitor injectors behaviour and identify possible thief zones. EOR techniques and new technologies as fresh water injection, polymer injection, etc. are already implemented or under evaluation to maximise water injection efficiency and field recovery factor.
Lattice Boltzmann Method for Simulation of Shale Gas Transport in Kerogen
Authors: Fathi Ebrahim , Akkutlu I. Yucel 
Published: October 2011

Abstract
Fluid mechanics of natural gas in organic-rich shale involves nano-scale phenomena which could lead to potential non-Darcian effects during gas production. In general, these are low-Reynolds number and non-continuum effects and, more importantly, pore-wall dominated multi-scale effects. In this study we introduce a new lattice Boltzmann method to investigate these effects numerically in simple pore geometries. The standard method has been developed in the 1980s to overcome the weaknesses of lattice gas cellular automata and has emerged recently as a powerful tool to solve fluid dynamics problems, in particular in the areas of micro-and nano-fluidics. The new approach takes into account molecular-level interactions using adsorptive/cohesive forces among the fluid particles and defining a Langmuir-slip boundary condition at the organic pore walls. The model allows us to partition mass transport by the walls into two components: slippage of free gas molecules and hopping (or surface transport) of the adsorbed gas molecules. Using the standard two-dimensional D2Q9 lattice, low-Reynolds number gas dynamics is simulated in a one-hundred nanometer model organic capillary and later in a bundle of smaller size organic nanotubes. The results point to the existence of a critical Knudsen number value for the onset of laminar gas flow under typical shale gas reservoir pressure and temperature conditions. Beyond this number the predicted velocity profile shows that the mechanisms of slippage and surface transport could lead to molecular streaming by the pore walls which enhances the gas transport in the organic nanopores. The work is important for development of new-generation shale gas reservoir flow simulators and it can be used in the laboratories for organic-rich shale characterization.
Lower Quality Natural Quartz Proppants Result in Significant Conductivity Loss and Reduction in Ultimate Recovery: A Case History
Authors: Syfan Frank E. , Anderson Robert W. 
Published: October 2011

Abstract
Progress in horizontal drilling and hydraulic fracturing techniques allow the oil and gas industry to get the most out of ultra tight, naturally fractured formations and unconventional reservoirs. The increasing price differential between crude oil and natural gas is resulting in unprecedented activity in the Bakken, Eagle Ford, Niobrara, and other oil rich shales. The industry is actively building drilling rigs and the fracturing companies are adding equipment and crews at an escalating rate to keep up with the market growth.
These events have placed demands on hydraulic fracturing consumables as never before. Proppant shortages are expected to worsen before additional capacity can begin to offer some relief. Consequently, more and more operating companies are pumping lower quality Natural Quartz Proppant (NQP) in deeper, hotter, and higher closure stress environments, some of which exceed conventional design limits. All this in an effort to maintain completion intervals which are comparable to the accelerated drilling programs.
Recent proppant testing indicates significant conductivity reductions over time as it relates to proppants with lower crush strengths when compared to the higher strength Northern Whites. These conductivity variations were identified using a Discrete Fracture Network (DFN) fracture simulation model which indicated substantial reductions in ultimate recovery and productivity over time. The conductivity and modeling results were compared to actual post-fracture analysis data in the Marcellus Shale. This comparison further substantiated the test results.
This paper challenges the industry concept that pumping lower quality crush resistant proppants in a shale reservoir will not result in productivity losses. The findings presented in this paper clearly show that creating and retaining fracture conductivity is a prerequisite to achieving high initial productivity, ultimate recovery, and maximizing project economics.
Environmentally Focused Crosslinked-Gel System Results in High Retained Proppant-Pack Conductivity
Authors: Holtsclaw Jeremy , Loveless David , Saini Rajesh , Fleming Jeff 
Published: October 2011

Abstract
This paper presents the retained conductivity results of a new environmentally focused fracturing fluid whose components are sourced from the food industry, as described in the US Code of Federal Regulations Title 21 (CFR 21) or the Generally Recognized as Safe (GRAS) affirmation process. The fluid is comprised of the following components: a low-residue polysaccharide gelling agent, a metal crosslinker, a surfactant, and a suite of breakers. The suite of breakers provides consistent fluid cleanup in retained conductivity testing in temperatures ranging from 120 to 200°F. Fracture conductivity testing was performed using a wet-gas cleanup protocol used in modeling hydraulically fractured wells.
Hydraulic fracturing and the environmental effects of the chemicals involved in the fracturing process have become the subjects of public discussion. This discussion has encouraged the petroleum industry to address public concern regarding the potential environmental impact of chemicals used in fracturing. Service companies have responded by improving their current chemical portfolio and developing new environmentally focused chemical technologies. This paper describes an environmentally focused metal-crosslinked polysaccharide fluid that not only is more environmentally acceptable under the criteria described in this work, but also has little or no proppant-pack conductivity impairment, as measured by fracture conductivity testing.
Wet-gas retained conductivity of 1-lbm/ft2 20/40-mesh Ottawa sand was performed with humidified nitrogen gas flow. Retained conductivity of 84 to 100% was obtained after wet-gas cleanup for temperatures ranging from 120 to 200°F under a 2,000-psi closure stress. All conductivity tests were performed between Ohio sandstone wafers with filter-cake buildup from dynamic fluid-loss testing. Wet-gas retained conductivity was verified by a third-party laboratory. These results indicate that a fracturing fluid can be designed using defined environmental criteria based on food grade materials to provide similar performance and excellent retained conductivity.
Permeability Estimation of Damaged Formations Near Wellbore
Authors: Shi Xiaoyan , Prodanovic Maša , Holder Jon , Gray K. E. , DiCarlo David 
Published: October 2011

Abstract
We propose a numerical model for permeability estimation in damaged formations (e.g. sediments invaded by fines or sand crushing remnants). Grains of two length scales are present, but only larger ones are load-bearing. Porous media were modeled in Itasca's PFC3D, ensuring mechanical stability and making the particle positions and arrangement available for pore throat network analysis. The standard network modeling approach for analysis of packing of nearly equal grains (Delaunay tessellation) cannot be used since grains of two different length scales create a high portion of distorted pores. The main novelty of this work is adapting the network flow model to work with two length scales, and we present both the network creation and flow model in the multi-scale case.
The effects of particle size and initial formation porosity on formation damage are studied in detail. Our study confirms that large particles tend to occupy the formation face, while small particles invade deep into the formation. Moreover, particles which are smaller than pore throats (entrances) impair permeability more than those larger than pore throats. Our study also indicates that a higher initial formation porosity leads to more particle invasion and permeability impairment. Thus in order to reduce formation damage, mud particle size distributions should be carefully selected according to given formation properties.
Despite some simplifications in our initial modeling, it may nevertheless serve as a tool to predict formation damage according to given parameters, and to understand the mechanism of formation damage from a microscopic point of view. Further, while our motivation is formation damage during drilling, the modeling presented is applicable to any situation where migration of finer particles impairs a granular or sandstone medium.
Sweep Efficiency of Heavy Oil Recovery by Chemical Methods
Authors: Kumar Rahul , Mohanty Kishore K. 
Published: October 2011

Abstract
The goal of the present work is to evaluate the recovery efficiency of a heavy oil by injection of brine followed an alkaline-surfactant (AS) formulation in a quarter 5-spot sand pack. Reservoir sand was packed in a 2D cell resembling a quarter 5 spot well pattern. Brine flood for 2.5 PV was followed by the alkali surfactant flood conducted at different salinities. The oil recovery, oil cut, emulsion type and pressure drop were monitored. The brine flood recovered around 33-35% of OOIP and additional 18-24% could be recovered by the alkaline-surfactant solution. At the high salinity, the incremental oil due to AS solution came out quick at a high oil cut. For low salinity, the incremental oil recovery was more gradual.