bluuebunny/crossref_metadata_2025 huggingface dataset:
Conventional Analysis for the Determination of the Horizontal Permeability from the Elliptical Flow of Horizontal Wells
Authors: Escobar Freddy H. , Montelegre-M Matilde
Published: December 2007

Besides the regular four flow regimes normally seen during a pressure test of horizontal wells, it is possible, under special circumstances, to observe such additional flow regimes as spherical, hemi-radial, linear (reservoir channel) and elliptical. The last flow regime is characterized by a slope of 0.36 of the pressure derivative curve and occurs between the early linear flow and the pseudo-radial flow periods. This may have been overlooked in horizontal well test analysis, because it is often masked by the other flow regimes, unless the conditions are just right.

The elliptical flow regime has been previously mentioned by very few researchers5-7. A methodology for its characterization has been also introduced using the pressure derivative concept and TDS technique7. However, conventional analysis for the characterization of this has not yet been reported in the literature. This flow regime is very useful to estimate the horizontal permeability, especially, when the pseudo-radial flow is very short or unclear, or simply, when it is desired to verify this estimation.

In this paper, equations for the estimation of the horizontal permeability and elliptical skin factor are developed for both gas and oil horizontal wells, so that the mentioned parameters can be estimated, respectively, from the slope and intercept of linear plot of pressure versus time to the power 0.36. The equations were successfully tested with two field examples previously worked in the literature.
Special Issues in the Stress Analysis of Casing Strings in Steam-Injection Wells: Mathematical Development and Design
Authors: Garside R. , Pattillo P. D. , Pattillo P. D. II , Sathuvalli U. B.
Published: December 2007

This paper presents a mathematical model of casing strings subjected to thermal loads in steam injection wells. The model includes the effects of temperature on material properties and the effects of wellbore curvature and pre-stress during the heating cycle. Several counter-intuitive aspects of the casing stress state during cooling/unloading are examined. Example calculations are used throughout to illustrate key insights.
Accreditation of an Oil Company Training Scheme for Graduate Engineers
Authors: Saadawi Hisham , Al Sammarrai Wathik
Published: December 2007

Abu Dhabi Company for Onshore Oil Operations (ADCO) is the major oil and gas producer in the United Arab Emirates (UAE). For the past ten years, ADCO has implemented a Graduate Development Program (GDP) to train and develop the young UAE national engineers who join the ADCO every year.

With the increasing development activities in the Company and shortage of experienced personnel in the oil industry, there is a pressing need to accelerate the training and development of the young UAE national engineers. In order to ensure that quality is maintained and to benchmark the Graduate Development Program, ADCO applied to the various engineering institutions in the UK to accredit the program. The training scheme was successfully accredited by four major engineering institutions in the UK.

This paper outlines ADCO Graduate Development Program and the need for accrediting the Program. The differences between certification and registration of engineers versus accreditation of the training program are discussed.

The paper also describes how an organization can accredit its training program and the benefits of such accreditation.
Designing Cement Slurries for Preventing Formation Fluid Influx After Placement
Authors: Santra Ashok , Reddy B. R. , Antia Mfon
Published: December 2007

Formation fluid influx into cement slurries immediately after placement presents not only a short-term problem, for example losing the slurry due to shallow water flows, but also presents a long-term problem, for example gas flow and pressure buildup behind the casing. It is critical that cement slurries be designed carefully when such problems are anticipated. Cement slurries that often offer the best solution to resist the formation influx are those that do not gel while being pumped then gel/set and gain strength rapidly once placed. These are sometimes referred to as "right-angle set" cements and should possess the following attributes in laboratory design testing:Maintains a low rheological profile while pumping for lower ECDs.Predictable thickening and set times.Retains the ability to transmit hydrostatic pressure under static conditions until the cement is ready to gel/set.Short gel to set time under static conditions, often termed "transition time."Short waiting on cement (WOC) time.

This paper shows that although a cement slurry having a "right-angle set" may ensure the first two benefits, it does not always guarantee the latter two when present behind a casing. For example, some slurries might reach thickening time and become unpumpable rapidly, but strength development may not occur until long afterward, due to a time lag between thickening and hydration time (set time) of cement. In such cases, slurry should be designed such that the thickening time and hydration time are essentially identical. Novel slurries that maintain low rheological profiles while the slurry is being placed, then set and gain strength quickly due to cement hydration afterward, have been developed for a variety of densities and downhole temperatures. Results from laboratory and related field case histories will be presented.
Scalability and Load-Balancing Problems in Parallel Reservoir Simulation
Authors: Gratien J. M. , Guignon T. , Magras J. F. , Quandalle P. , Ricois O.
Published: December 2007

New parallel reservoir simulator software designed for Linux clusters enable to overcome hardware limitation and to simulate models with large amount of data. Reservoir engineering industry is very interested in using ever growing dataset with more and more complex physics and detailed models. The key issue still remains running simulations in an acceptable CPU time. As, the trend in hardware technologies is not to improve drastically the performance of individual CPUs but to facilitate the aggregation of computation facilities (with high bandwidth network, multi-core architectures …), the challenge is to improve the efficiency of reservoir simulation software on a large number of processors.

New numerical difficulties and performance problems appear when the number of cells and the number of processors are growing. As a matter of fact, the architecture of Linux clusters is very sensible to memory distribution and load balancing: the cost of parallel solver algorithm is usually sensible to the size of the reservoir model (lack of scalability) and the consequences on CPU performance can no more be neglected;the domain decomposition algorithms used to distribute data between processors have a great influence on the computing load balancing between processors;using adaptive numerical schemes with dynamic space criteria (AIM schemes, flash algorithms based on the thermodynamic state of each cell) is a source of unbalance that cannot statically be resolved;simulation result storages on irregular data structures, such as unstructured grids, multilateral smart wells and perforated cells, lead to store an important amount of information during the simulation. With the variety of IO subsystems found on Linux clusters the simulator must be able to adapt its IO strategy to the underlying IO library/file system and hardware.

In this paper, we present different approaches to overcome these kinds of problems. We discuss technical choices such like: advanced scalable linear solver algorithm;load balancing issue with different domain decomposition strategies;dynamic space criteria, mesh partitioner strategy and parallel solver performance management;flexible IO strategy from simple file system to more complex parallel file system or database.

We have developed and benchmarked these different solutions on published reference large scale problems and actual case studies with several tens millions of cells. We analyze the results and discuss the efficiency of each solution to overcome the scalability difficulties and performance limitations due to load unbalance.
Efficient Parallel Simulation of CO2 Geologic Sequestration in Saline Aquifers
Authors: Zhang Keni , Doughty Christine , Wu Yu-Shu , Pruess Karsten
Published: December 2007

An efficient parallel simulator for large-scale, long-term CO2 geologic sequestration in saline aquifers has been developed. The parallel simulator is a three-dimensional, fully implicit model that solves large, sparse linear systems arising from discretization of the partial differential equations for mass and energy balance in porous and fractured media. The simulator is based on the ECO2N module of the TOUGH2 code and inherits all the process capabilities of the single-CPU TOUGH2 code, including a comprehensive description of the thermodynamics and thermophysical properties of H2O-NaCl-CO2 mixtures, modeling single and/or two-phase isothermal or non-isothermal flow processes, two-phase mixtures, fluid phases appearing or disappearing, as well as salt precipitation or dissolution. The new parallel simulator uses MPI for parallel implementation, the METIS software package for simulation domain partitioning, and the iterative parallel linear solver package Aztec for solving linear equations by multiple processors. In addition, the parallel simulator has been implemented with an efficient communication scheme. Test examples show that a linear or super-linear speedup can be obtained on Linux clusters as well as on supercomputers. Because of the significant improvement in both simulation time and memory requirement, the new simulator provides a powerful tool for tackling larger scale and more complex problems than can be solved by single-CPU codes. A high-resolution simulation example is presented that models buoyant convection, induced by a small increase in brine density caused by dissolution of CO2.
Engineering Rhamnolipid Biosurfactants as Agents for Microbial Enhanced Oil Recovery
Authors: Fang Xiangdong , Wang Qinhong , Bai Baojun , Liu Cai Xi , Tang Yongchun , Shuler Patrick J , Goddard Willliam A.
Published: December 2007

This investigation considered engineered rhamnolipid biosurfactants as EOR agents that potentially could be manufactured at low cost from renewable resources, and have lower toxicity than synthetic EOR surfactants. This particular biosurfactant comes mainly from the microbe Pseudomonas aeruginosa. Disadvantages of working with this strain include that the chemical structures of the produced rhamnolipids are not easily controlled, plus there is a preference to use instead a completely non-pathogenic microbe. Towards that end, the study took the approach to clone the genetic information from a P. aeruginosa strain into E. coli to manipulate systematically the structure of the created rhamnolipids and evaluate their EOR performance by themselves (no co-surfactant or viscosity chemical added).

Six E.coli strains (ETRA, ETRAB, ERAC, ETRABC, ETRhl, ETRhl-RC) that carry different combinations of the genes involoved in rhamnolipid bio-synthesis were successfully engineered and tested for their rhamnolipid production. Sand-pack core flooding tests were run to evaluate and compare the effectiveness of these products as agents for enhanced oil recovery. The brine with optimized pH and salt concentration in which a given biosurfactant product has its lowest IFT was used to saturate the core, perform a waterflood, and prepare the surfactant solution. Injection of 6 PV of only a 250 ppm rhamnolipid biosurfactant solution and 4 PV of a brine chaser could recover as much as half of the waterflood residual hydrocarbon (n-octane). The engineered E. coli strains that include more of the implanted genetic code had the better performance in these oil displacement tests. The IFT, biosurfactant concentration and pH of effluents from core flooding were monitored to address EOR mechanisms and quantify the adsorption of each product in the sand pack.
Horizontal Fracture Stimulation Success in the Alpine Formation, North Slope, Alaska
Authors: Schneider Tim S. , Uldrich David O. , Hodge Richard , Barree Bob , Martin Michael W.
Published: December 2007

The Alpine field located on the North Slope of Alaska was developed using open-hole horizontal completions drilled along the maximum principle stress and dominant fault orientation (northwest/southeast). Open-hole completions were considered the best completion option based on rock mechanics, improved profile surveillance and cost. The original Alpine field development plan did not include hydraulic fracture stimulation based on the reservoir characterization. Well performance had proven to be economic in this Jurassic, marine sandstone without hydraulic fracturing, until drilling the CD2-37 well in 2003. The poor reservoir quality found in the southwestern edge of the field required stimulation to produce at economic rates. A hydraulic fracture treatment was performed resulting in a 200% production increase. Over the past three years, a stimulation program has evolved with improvements in candidate selection, performance and predictability. Future plans include continuing to stimulate candidate wells by incorporating horizontal completion technologies that are more conducive to multiple fracture technology.

This paper presents the evolution of the candidate selection process and a review of reservoir characterization as a result of the significant production improvements gained from hydraulic fracturing. We will also present how the Alpine full field model predictions have impacted the candidate selection process and discuss the stimulation design history that includes fracture fluid changes resulting from core analyses.
Modeling the Impact of Capillary Pressure Reduction by Surfactants
Authors: Gdanski Rick
Published: December 2007

Fluid recovery after fracturing treatments in tight gas reservoirs is often critical in obtaining maximum production rates. Fluid recovery aids in washing broken fracturing fluid out of the propped fracture and restores the relative permeability to gas in the invaded matrix of the fracture face. However, recovery of fracturing fluids from the invaded matrix requires overcoming both capillary pressure-driven imbibition and the capillary exit pressure that occurs at the fracture boundary between the matrix and propped fracture. Surface active materials, such as alcohols and surfactants, are often used to reduce the surface tension, and hence the capillary pressure functions in the matrix. These materials are expected to enhance recovery of the fracturing fluid from the matrix, improving load recoveries. Modeling this process with classical reservoir simulators is not possible because they do not allow for the impact of surface tension reduction on capillary pressure functions. A previously reported simulator for modeling fracturing fluid movement has been modified to accommodate the impact of surface tension reduction on capillary pressure. This simulator uses the simultaneous solution (SS) method for solving the two-phase flow equations, followed by calculation of the movement of chemicals based on the pressure solution at each time step. A new modification to the SS method has been developed to allow proper modeling of the impact of capillary pressure reduction by surfactants.

Surfactants can reduce capillary pressure in the matrix by reducing surface tension and/or by changing the wettability of the rock surface when they adsorb on a surface. The classical SS method does not maintain proper "mass balance" when surfactants are allowed to change the capillary pressure; the reason for which is demonstrated in this work. The new modification allows surfactants to impact capillary pressure through surface tension reduction and wettability changes.
Stimulation of Gas Shales: They're All the Same—Right?
Authors: Matthews H. Lee , Schein Gary , Malone Mark
Published: December 2007

In recent years, the upswing in drilling activity and the higher price of natural gas has caused the industry to focus more on non-conventional gas reservoirs. Heading up this list are gas shales. This peaked interest was brought on not only by an increase in natural gas prices, but also the apparent abundance of potential gas shales present in the continental United States and the well publicized success of the Barnett Shale of North Texas. In order to obtain commercial production from these low permeability shale reservoirs, fracture stimulation is required. Numerous technical papers have been published on the merits and success of stimulation in this well documented reservoir. While slickwater treatments have become the stimulation method of choice, it is important to note that several other stimulation and completion techniques have been employed that have resulted in economic and commercially viable Barnett Shale producers over the last 20 years. Although there has been tremendous success with slickwater fracture treatments, many believe this technology can be universally applied to all gas shale reservoirs. While this may be the case in the Barnett Shale it is not necessarily true for other prospective shale basins being explored.

This paper will include a brief history of Barnett Shale stimulation practices and go on to address shale reservoirs and characteristics that make each one unique from a stimulation perspective. It is not the attempt of the authors to provide a stimulation checklist, but to identify a number of shale reservoir characteristics and their effect on the process of stimulation optimization. Case histories in the Ft. Worth Barnett and Permian Basin Barnett and Woodford Shales will be used to infer key differences in reservoir attributes and how these differences influence stimulation decisions.
Experimental Investigation and Modeling of Naphthenate Soap Precipitation Kinetics in Petroleum Reservoirs
Authors: Sarac S. , Civan F.
Published: December 2007

The mechanism, reaction kinetics, and rate equation of the naphthenate soap precipitation are determined by means of experimental and theoretical investigations. Such information may be important for controlling and minimizing the well productivity loss by naphthenate soap precipitation in petroleum reservoirs. This was accomplished by three means: a) Static bottle tests were conducted to determine the precipitation rate at various pH and temperature conditions, b) particle size growth of the naphthenate soap precipitates was investigated under static conditions to determine the governing growth mechanism, and c) core flow tests were run to determine the effect of the naphthenate soap precipitation on permeability impairment in porous media. The naphthenate soap precipitation rate was correlated with respect to the considered parameters based on a power-law expression. The measured particle size data indicated the growth of particle size with time. Finally, the core flow tests allowed the determination of the impact of the naphthenate soap precipitation in porous media in terms of the permeability impairment and damage ratio. The results of these studies may be instrumental in avoiding or minimizing formation damage problems associated with the naphthenic acid containing petroleum reservoirs.
Remediation of Proppant Flowback—Laboratory and Field Studies
Authors: Nguyen Philip D. , Weaver Jimmie D. , Rickman Richard D. , Sanders Michael W.
Published: December 2007

This paper presents the results of laboratory studies and field case histories of a remedial treatment technique using a low-viscosity consolidation fluid system that is placed into the propped fractures by coiled tubing (CT) or jointed pipe coupled with a pressure pulsing tool. The treatment fluids are designed to provide consolidation (for previously placed proppant) near the wellbore to glue the proppant grains in place without damaging the permeability of the proppant pack.

Laboratory flow testing indicates that the proppant pack in a fracture model under closure stress only requires low-strength bonds between proppant grains to withstand high production flow rates. The consolidation treatment transforms the loosely packed proppant in the fractures and the formation sand close to the wellbore into a cohesive, consolidated, yet highly permeable pack. Field case histories are presented and the treatment procedures, precautions, and recommendations for implementing the treatment process are discussed. One major advantage of this remedial treatment method is the ability to place the treatment fluid into the propped fractures, regardless of the number of perforation intervals and the length of the perforated intervals without mechanical isolation between the intervals. The fluid placement efficiency of this process makes remediation economically feasible, especially in wells with marginal reserves.
Zeta Potential Altering System for Increased Fluid Recovery, Production, and Fines Control
Authors: Kakadjian Sarkis , Zamora Frank , Venditto Jim
Published: December 2007

This paper presents a new zeta potential altering system that is based on an inner salt developed to enhance the water flowback recovery on borate and slick-water frac jobs. The system also aids in the control of fines. The mechanism of this system is to modify the zeta potential on particles such as frac sand from -50 mV, or coal from -28 mV, to more neutral values. This modification helps increase the potential for particle agglomeration and changes in the sand pack in the fracture to increase fluid recovery and production.

Results from lab studies have shown that the flow rate ratio for a 2% KCl solution through sand packs (treated/not treated) increased up to 45% when treated with 6.0 gal of chemical per 1,000 lb of frac sand. Similar results were obtained on conductivity tests using ceramic proppant, improving conductivity from 7,150 mD-ft to 11,387 mD-ft at 2,000 psi closure stress.

This new system does not interfere with fracturing fluid rheological profiles for borate systems and improves friction reducing characteristics in slick-water systems.

The system was tested in the field on a slick-water job, where the additive was mixed in the blender tub.
Mixed Finite Element and Related Control Volume Discretizations for Reservoir Simulation on Three-Dimensional Unstructured Grids
Authors: Matringe S. F. , Juanes R. , Tchelepi H. A.
Published: December 2007

The numerical discretization of the reservoir flow equations is a challenging problem on three-dimensional unstructured grids and in the presence of full-tensor permeabilities. Finite volume methods based on a two-point flux approximation (TPFA) do not properly account for grid distortion or permeability anisotropy that is misaligned with the grid. Over the past decade, multipoint flux approximation (MPFA) methods have been devised to address these issues. Recent research has shown, however, that MPFA methods may lead to unphysical nonmonotonic solutions for high anisotropy ratios or strongly distorted grids.

In this paper, we work in the mathematical framework of mixed finite element methods (MFEM). We study a low- and high-order accurate MFEM, based on the lowest order Raviart-Thomas space (RT0) and the Brezzi-Douglas-Marini space of order one (BDM1). On tetrahedrons, the BDM1 space can be localized into a compact finite volume method through the use of an appropriate numerical quadrature. However, this is not possible for hexahedrons.

The main result of this paper is the development of a new mixed finite element method for 3D hexahedral grids, which leads to a multipoint flux approximation finite volume method through the use of a vertex-based numerical quadrature. This is possible because the new velocity space is designed so that the degrees of freedom are the normal component of the velocity field at the vertices of each face. This establishes for the first time a direct link between MFEM and MPFA methods on 3D hexahedral grids.

We compare the performance of classical (RT0 and BDM1) mixed finite element methods with the newly developed method on a number of test cases. We conclude that high-order methods lead to higher-quality velocity fields that are less sensitive to the choice of the grid, and that they have better monotonicity properties for highly anisotropic full-tensor permeability fields. While the added benefit of the new space is that it can be approximated by a cell-centered finite volume scheme, our numerical experiments indicate that the accuracy of the scheme is reduced.
The Development of a Scale Management and Monitoring Program for a High-Temperature Oil Field During the Production-Decline Phase of the Life Cycle
Authors: Jordan Myles , Sørhaug Eyvind , Elrick Morag , Marlow David
Published: December 2007

This paper presents field results from scale squeeze treatments carried out on platform wells within a high temperature (150C) field in the Norwegian sector of the North Sea. Scale control and the resulting squeeze treatments to production wells were highlighted as the most expensive item in the production chemical budget. The development of a cost-effective squeeze and monitoring policy has been critical to reducing the operating cost of this asset as the produced water cut rose.

The decision to use both aqueous and emulsified scale inhibitor for treating these high temperature production wells was arrived at after an extensive series of laboratory tests including formation damage coreflood studies and an assessment of chemical retention at this elevated temperature. The field data from these wells will be presented comparing treatment lifetimes and clean up rates between conventional treatments and the novel emulsion technology

A key factor to the success of such treatment is an understanding of chemical placement and the effectiveness of the treatment chemicals. Evaluation of residual chemical concentration or scaling ion chemistry has long been used in monitoring programs and more recently probes have been developed which increase the rate of evaluation/interpretation. All these monitoring methods prove that the chemical is present in the brine when sampled or that scale formation is not occurring at the point of brine analysis. This paper outlines the experimental methods developed to evaluate the suspended solids collected from the produced brine by environmental scanning electron microscope (ESEM) and the associated brine chemistry to evaluate the scale risk within the produced fluids. The combination of these methods has improved the integrated scale management program in terms of evaluating scale squeeze placement effectiveness, squeeze lifetime and provides the confidence t0 extend the period between scale squeeze treatments. Also, and in some cases treatments were stopped where brine analysis alone would have suggested further scale squeeze applications were required.
Field Trial Design and Analyses of Production Data from a Tight Gas Reservoir: Detailed Production Comparisons from the Pinedale Anticline
Authors: Vincent M. C. , Huckabee Paul , Conway Michael
Published: December 2007

Field trials of new methodologies, products or technologies are considered to be an effective way to gauge the true value of such innovations. However it is difficult and expensive to conduct a rigorous field trial, especially in tight, multi-layered reservoirs, and proper design and analyses are critical to accurately interpret the results. In multi-layered reservoirs the production from individual frac stages must often be evaluated with production logs - this additional expense accentuates the need to carefully design the field trial and thoroughly analyze the resulting data to extract as much value as possible. This paper will provide a detailed comparison of well productivity in the Pinedale Anticline as a function of proppant type and subinterval. Well production has been normalized by many parameters, including reservoir kh, khΔP, kh*(Pr2-Pf2), Φh, and also compared by well location to determine the degree to which those techniques provide similar conclusions. In addition to describing how these field results influence proppant selection in the Pinedale Anticline, this paper will describe many aspects of field trial planning, as well as the proper handling of data to assist in the design of future trials.

This paper will review the following topics: –Design of the field trial–Efforts to minimize variables–Well selection to promote valid offset comparisons–Data handling techniques to minimize bias–Production logging of wells – calibration and timing–Detailed comparison of production data, normalized with six methods to determine whether consistent conclusions can be reached–Statistical analyses to determine whether statistically significant conclusions can be drawn with a high degree of confidence

The results of this study will also be compared to other published field trials to examine well populations, data consistency, and to assess whether studies in similar reservoirs carry similar findings. This paper will summarize the conclusions that are consistent between numerous tight gas field studies in the region, and highlight changes to fracture treatments which have consistently improved well productivity and profitability in these reservoirs.
Advanced Nitrate-Based Technology for Sulfide Control and Improved Oil Recovery
Authors: Dennis D. M. , Hitzman D. O.
Published: December 2007

Industry now recognizes that nitrate based technology is preferred to biocide treatments for the control, prevention, and removal of biogenic produced sulfide in sea and produced water injection systems. Advanced formulations with varying ratios of nitrate/nitrite have proven superior to nitrate-only treatments by providing increased effectiveness at lower treating levels with reduced costs. Concurrent with sulfide control these advanced nitrate/nitrite combination formulations have demonstrated significant increased oil recovery in field operations. Data show the dual benefits of the advanced nitrate/nitrite technology to offer industry the opportunity to reduce operating costs while additionally producing more oil.
Kinetic Parameters for Dilute Epoxy Resins Measured by Nuclear Magnetic Resonance Spectroscopy
Authors: Rickman Richard D. , Wilson J. Michael , Weaver Jim D.
Published: December 2007

Thermosetting resins are employed in a wide variety of oilfield applications. The development of dilute resin formulations offers several advantages over conventional resin systems and new resin applications are making increasing use of dilute formulations. Knowledge of the thermodynamic properties of the resin system is essential to ensure that they perform as expected. We report here on the use of nuclear magnetic resonance, NMR, to measure activation energies, enthalpies, entropies, and frequency factors for the curing of a diglycidylether bisphenol A epoxy resin with a modified cycloaliphatic amine hardener. Results calculated with this technique are presented here and are in good agreement with values calculated using more conventional techniques.
Simulation of Surfactant-Aided Gravity Drainage in Fractured Carbonates
Authors: Adibhatia B. , Mohanty K. K.
Published: December 2007

Waterflooding often recovers little oil from carbonate reservoirs because carbonate reservoirs are usually oil-wet and fractured. Dilute surfactant solution injection into the fractures can improve oil production from the matrix by lowering the oil/water interfacial tension (IFT) and by altering the wettability of the rock to intermediate/water-wetting. A 3-D, two-phase, multicomponent, finite-difference, fully-implicit numerical simulator is developed that incorporates adsorption, phase behavior, wettability alteration, and related capillary pressure / relative permeability variations. The reliability of the simulator is established by comparing the core-scale simulation results with experimental results obtained in our laboratory. IFT reduction, wettability alteration and permeability are varied to study the sensitivity of the surfactant-aided gravity drainage to these process parameters. Wettability alteration drives the oil production at the early stage, but gravity is the major driving force afterwards. Surfactants which alter the wettability to a water-wet regime give higher recovery rates for higher IFT systems. Surfactants which cannot alter wettability give higher recovery for lower IFT systems. Extent of wettability alteration increases the rate of oil recovery. Recovery rate decreases with permeability significantly for a low tension system, but only mildly for high tension systems.
Accelerating Effect of Surfactants on Gas Hydrates Formation
Authors: Pakulski Marek
Published: December 2007

Low dosage gas hydrate inhibitors (LDHI) are divided into two categories; kinetic hydrate inhibitors (KHI) and antiagglomerants (AA). KHI are mostly polymeric or oligomeric compounds while all AA have surface active properties. AA molecules must have hydrophilic "head" attaching to a surface of hydrate particle and hydrophobic "tail" to repel other hydrate particles; thus, preventing hydrate agglomeration. All surfactants having hydrophilic and hydrophobic functionality have some AA properties; however, only a handful of such compounds have found commercial applications in the oilfield.

Some surfactants present in the liquid water phase accelerate formation of gas hydrates. Foaming agents are particularly strong hydrate accelerators. Foamers, if present in water solution, can diminish or nullify the protecting effect of polymeric KHI. Some KHI and practically all AA chemicals used for hydrate control in the oilfield have foaming properties that could result in faster hydrate formation than similar non-foaming products. In some situations, gas producing wells are treated with foaming agents to enhance gas production through improved water unloading. The gas/water stream can require hydrate protection due to Joule-Thomson cooling effect or because of pressure/temperature (p/T) conditions in flowlines. Hydrate conditions can be encountered during flow back operation from foam fractured gas wells. Such conditions must be predicted and prevented through a proper flow back regime or chemical addition to the fluid prior to fracturing operation.

Laboratory experiments proved the accelerating hydrate formation effect of three main types of foaming surfactants; nonionic, cationic and amphoteric. However, the most dramatic effect was when an insufficient amount of methanol was mixed with the foaming agents. A possible mechanism of the acceleration effect could be related to increased gas/water surface contact in foams; thus, accelerating dissolution of gas in water. Emulsifying properties of foaming agents contribute also to the hydrate accelerating phenomenon.
A Study on Catalytic Aquathermolysis of Heavy Crude Oil During Steam Stimulation
Authors: Wen Shoubin , Zhao Yujian , Liu Yongjian , Hu Shaobin
Published: December 2007

The aquathermolysis of Liaohe heavy crude oil during steam stimulation was studied by using molybdenum oleate as oil-soluble catalyst for the reaction in this paper. The laboratory experiment shows that viscosity-reduction ratio of heavy oil is over 90% at 240°C, 24hr, with 0.5wt% catalyst solution. The field test that applied aquathermolytic technology in puff-and-huff operation was carried out in Qi-40 and Qi-108 blocks of Liaohe oilfield. As a result, significant viscosity reduction and production increase were obtained. Further filed test indicated that the cycle decline rate of heavy oil production in puff-and-huff operation was improved by aquathermolytic technology.
Acceleration of Streamline Simulation Using Adaptive Mesh Refinement Along Streamlines
Authors: Andrianov Nikolay , Bratvedt Kyrre
Published: December 2007

Streamline methods have become an efficient technology for reservoir simulation. The key assumption of the method is that the pressure field can be updated relatively less frequently, and the saturations can be transported along the streamlines defined by the velocity field. The efficiency of the solution method along the streamlines is very important for the overall efficiency of the method.

In this work, the acceleration of the saturation transport using adaptive mesh refinement (AMR) along streamlines is investigated. The refinement strategy is based on the multi-scale wavelet techniques. The one-dimensional solution is decomposed into a set of coarse-grid cell values and a set of solution details, which indicate the smoothness of the solution. This decomposition is recursively applied to the resulting representation until the coarsest mesh level is reached. From this multi-resolution representation of the solution an adaptive grid is constructed by thresholding of negligible details. Then, a second-order finite volume method is used on the obtained adaptive grid.

The performance of the resulting multi-resolution scheme on a synthetic and a real reservoir model is studied, using two-phase incompressible and three-phase black oil compressible data. It is shown that the use of the AMR technique can provide up to a five-fold acceleration compared to the solution of the same numerical method on a uniform grid. The proposed technique is implemented in a commercial reservoir simulator.
Gas Drying Using a Pass-Through Hydrate Crystallizer
Authors: Tatro S. R. , Sheps K. M. , Brazel L. A. , Osegovic J. P. , Max M. D.
Published: December 2007

Unwanted hydrate (Clatrhrate) formation is a major flow assurance issue for exploitation of hydrocarbon resources, especially in the more remote and colder environment of offshore deep water. Unwanted hydrate may form as the temperature of extracted gas and oil falls following its removal from its reservoir and the pressure, temperature, and water concentration become suitable for hydrate formation. Preventing unwanted hydrate formation is presently accomplished mainly using inhibitors that retard the nucleation, growth, and agglomeration of hydrate or through the crystallization in petroleum of many crystallites (cold flow).

A new approach to preventing the formation of unwanted hydrate is described. In this method, the removal of water from the pipeline system, without which unwanted hydrate cannot form, is the objective. It is not necessary to remove all water; but only to keep the vapor pressure of dissolved water low enough so that unwanted hydrate will neither nucleate nor grow. Water is extracted through the controlled crystallization of hydrate, which extracts dissolved water from the hydrocarbons in an innovative manner.

In the proposed method, hydrate is formed on surfaces of a permeable heat exchanger through which the hydrate is dissociated and the water removed. Dynamically forming hydrate on the exterior (pipeline side) and dissociating on the interior side of the porous surface (in a low pressure chamber) allows for collection and removal of water from the pipeline. This eliminates the potential for unwanted hydrate formation of the mixture down stream. More than one water removal stage in a pipeline may be required. The method holds promise to achieve hydrate flow assurance on the seafloor without the use of chemicals or extensive industrial plants at a very low energy cost.
Characterization of the Chemical Properties of Crude Oils To Explain Observed Asphaltene Inhibitor Specificity
Authors: Squicciarini Michael , Yen Andrew , Smith Donald F. , Rodgers Ryan P. , Marshall Alan G. , Klein Geoffrey C.
Published: December 2007

Asphaltenes are typically defined by solubility as benzene soluble and pentane or heptane insoluble. The deposition and precipitation of flocculated asphaltenes in the oilfield can severely reduce the permeability of the reservoir, cause formation damage and can also plug-up the wellbore and tubing. Asphaltene inhibitors have been used with success in preventing these precipitation/deposition problems. Based on laboratory and field tests, it was found that asphaltene inhibitor performance is oil specific. We present results obtained by analyzing crude oil from two different geographic regions. The crude oil and asphaltene samples were characterized by a variety of analytical techniques including total acid number (TAN), elemental analysis, and Fourier transform infrared spectroscopy (FT-IR). Electrospray ionization Fourier transform ion cyclotron resonance mass spectrometry (ESI FT-ICR MS) was used to further characterize the two different crudes and their associated asphaltenes. Substantial differences between the relative abundance of heteroatom-containing compound classes were found for the two oils. The relationship between these findings and asphaltene inhibitor performance specificity is discussed. The results from this study provide a greater understanding on how different inhibitors interact with asphaltenes thus enhancing the ability to develop the next generation of asphaltene inhibitors.
Coupling Chemical Kinetics and Flashes in Reactive, Thermal and Compositional Reservoir Simulation
Authors: Kristensen M. R. , Gerritsen M. G. , Thomsen P. G. , Michelsen M. L. , Stenby E. H.
Published: December 2007

Phase changes are known to cause convergence problems for integration of stiff kinetics in thermal and compositional reservoir simulations. We propose an algorithm for detection and location of phase changes based on discrete event system theory. The algorithm provides a robust way for handling the switching of variables and equations required when the number of phases changes. We extend the method to handle full phase equilibrium described by an equation of state. Experiments show that the new algorithm improves the robustness of the integration process near phase boundaries by lowering the number of convergence and error test failures by more than 50% compared to direct integration without the new algorithm.

To facilitate the algorithmic development we construct a virtual kinetic cell model. We use implicit one-step ESDIRK (Explicit Singly Diagonal Implicit Runge-Kutta) methods for integration of the kinetics. The kinetic cell model serves both as a tool for the development and testing of tailored solvers as well as a testbed for studying the interactions between chemical kinetics and phase behavior. A comparison between a K-value correlation based approach and a more rigorous equation of state based approach to phase equilibrium shows that phase behavior may significantly impact the reaction paths.
Fluid-Loss Control Improves Performance of Viscoelastic Surfactant Fluids
Authors: Huang Tianping , Crews James B.
Published: December 2007

Viscoelastic surfactant (VES) fluids have been widely used as gravel-packing, frac-packing and fracturing fluids for more than a decade because the fluids exhibit excellent rheological properties and maintain low formation damage characteristics compared with crosslinked-polymer fluids. Due to its non-wall-building property, VES fluid has much higher fluid leak-off into the reservoir matrix than wall-building polymer fluid. For frac-packing this has limited VES use to reservoirs with permeability of less than 1000 md and, in most cases, less than 250 md. Excessive fluid leak-off also significantly increases the cost of treatment.

This paper will introduce new technology for controlling the fluid loss of VES fluids to about 300°F. New fluid loss control agents have been developed that, through chemisorption and surface charge attraction, associate with VES micelles to produce a pseudo-filtercake of viscous VES fluid that significantly reduces the rate of fluid loss. Use of this technology will reduce the VES fluid volume required for a given treatment by up to two-thirds and extends the permeability range of VES fluids to about 2000 md. The fluid loss control agents are slowly water-soluble particles that are used at relatively low concentrations. The particles will be dissolved and/or flowed back with the producing fluid. The rate of the pseudo-filtercake clean-up is enhanced by use of internal VES breakers. The results of rheology, leak-off, and core flow tests will be presented for the VES fluid systems at temperatures 150°F and 250°F.
Operator-Based Multiscale Method for Compressible Flow
Authors: Zhou H. , Tchelepi H. A.
Published: December 2007

Recently, multiscale methods have been developed for accurate and efficient numerical solution of large-scale heterogeneous reservoir problems. A scalable and extendible Operator Based Multiscale Method (OBMM) is described here. OBMM is cast as a general algebraic framework of the multiscale method. It is very natural and convenient to incorporate more physics in OBMM for multiscale computation.

In OBMM, two multiscale operators are constructed: prolongation and restriction. The prolongation operator can be constructed by assembling basis functions, and the specific form of the restriction operator depends on the coarse-scale dis-cretization formulation (e.g., finite-volume or finite-element). The coarse-scale pressure equation is obtained algebraically by applying the prolongation and restriction operators on the fine-scale flow equations. Solving the coarse-scale equation results in a high quality coarse-scale pressure. The fine scale pressure can be reconstructed by applying the prolongation operator to the coarse-scale pressure. A conservative fine-scale velocity field is then reconstructed to solve the transport equation.

As an application example, we study multiscale modeling of compressible flow. We show that the extension of modeling from incompressible to compressible flow is really straightforward for OBMM. No special treatment for compressibility is required. The efficiency of multiscale methods over stan dard fine-scale methods is retained by OBMM. The accuracy of OBMM is demonstrate by several challenging cases including highly compressible multiphase flow in a strongly heterogeneous permeability field (SPE 10).
The Method of Distributed Volumetric Sources for Calculating the Transient and Pseudosteady-State Productivity of Complex Well-Fracture Configurations
Authors: Valkó P. P. , Amini S.
Published: December 2007

The method of Distributed Volumetric Sources (DVS) is developed to solve problems of transient and pseudo steady state fluid flow. The basic building block of the method comprises calculation of the analytical response of a rectilinear reservoir with closed outer boundaries to an instantaneous volumetric source, also shaped as a rectilinear body. The solution also provides the well-testing derivative of the response to a continuous source in analytical form. This can be integrated over time to provide the pressure response to a continuous source. For production engineering applications, we cast the results into a transient/pseudo-steady productivity index form. The new method is validated through comparison to results of some of the well known well-testing solutions for simple configurations such as vertical wells with full and partial penetration, horizontal wells with unform flux and infinite conductivity, and fractured wells with uniform flux, finite or infinte conductivity. The results show a very good agreement with the existing models. The main advantage of the new solution is its applicability over the more complex fracture/well configurations, some of which is studied in the paper.

The new method has shown to provide a fast, robust, and reliable way to pressure transient analysis, and well performance prediction whenever complex well/fracture configuration is considered.