bluuebunny/crossref_metadata_2025 huggingface dataset:
A Novel Technique for Treating Asphaltene Deposition Using Laser Technology
Authors: Zekri Abdulrazag Y. , Shedid Shedid A. , Alkashef Hassan
Published: December 2007

Crude oils produced in many parts of the world contain asphaltenes. Asphaltenes plugging is a well-known cause of near-wellbore formation damage. The deposition phenomenon of asphaltene is mainly due to thermodynamic changes. Asphaltene deposition leads to production loss and requires expensive and in many times environmentally unfriendly corrective measures. This project proposes a novel technique for cleaning asphaltenes with laser energy. A laboratory laser diode modules was used to perform experiments. A two-inch column of bitumen/powdered limestone mixture was placed on top of a powdered limestone column in a flow cell, and the flow rates were measured before and after the laser treatment. The rate was correlated with permeability of this powdered limestone column in absence of bitumen. In a second series of experiments, actual consolidated limestone cores were subjected to flow of asphaltenic crude to simulate the damage process (i.e. permeability reduction). The damaged cores were subjected to laser treatments at various laser intensity and treatment time intervals.

Experiment results indicated that asphaltene get disrupted after exposure to laser energy. However, the maximum amount of cleaning was noticed after an exposure of one hour and at a higher laser intensity. The increased flow rate measured employing the powdered limestone column after treatment can be used in an oil field to disrupt, or desegregate asphaltene from the vicinity of oil production wells. However, the simultaneous pumping is required during the laser treatment to avoid the reprecipitation of the disrupted asphaltene. The laser energy alters the thermodynamics of the system, which resulted in re-dissolve some of the asphaltene back into the liquid phase (reversible process). The proposed technique provides environmental friendly process and advanced technological breakthrough for treating asphaltene deposition in the petroleum industry.
Simultaneous Determination of Reservoir Pressure and Initial Fluid-in-Place from Production Data and Flowing Bottom Hole Pressure -- Theory
Authors: Wang Shie-Way
Published: December 2007

One frequently encountered difficulty in material balance calculation is lack of shut-in reservoir pressure. This work presents a new method that can be applied under pseudo steady-state conditions to simultaneously determine the average reservoir pressure and initial fluid in place using only surface production data and flowing bottom hole pressure. This new method is derived from a combination of a generalized material balance formulation and pseudo steady state theory and is applicable to both oil and gas reservoirs for single-phase flow with no water influx. This method does not rely on pressure build-up tests, knowledge of drainage area or permeability, but it requires flowing bottom hole pressure. For constant flowing bottom-hole pressure or variable production rate, this work presents an algorithm to convert fluctuating or constant flowing bottom hole pressure into corrected flowing bottom-hole pressure with a decline rate essentially identical to that of average reservoir pressure. Methods for analyzing transient flow are also discussed in this work. This new method is useful in analyzing surface production data and flowing bottom hole pressures for reservoirs significantly lacking data.
Conformance Water-Management Team Developments and Solutions on Projects in the Permian Basin
Authors: Creel P. , Vavrek G. , Honnert M. , Kelley R. , Tate R. , Dalrymple E. D.
Published: December 2007

A team was formed to solve field-wide conformance problems in a San Andres (dolomite) unit of the Slaughter Field, Hockley Co., Texas. The team's goal was to increase oil production and decrease production costs by understanding fluid movement through the reservoir. The team was comprised of operating and service company personnel who performed data analysis, and developed engineering and solution designs.

The reservoir conformance team identified, quantified, and fully described field conformance problems. Team members focused on understanding fluid movement through the total reservoir rather than on single wells. They developed a framework of data for designing successful conformance solutions. This framework includes data about the reservoir, completion design, drilling and workover history, production and well-test history, logs, diagnostic analysis, and placement options. The framework serves as a data-collection tool and as a tool for identifying missing data.1

This project involves the following tasks: (1) analyzing approximately 300 wells, (2) identifying conformance candidate (pilot) wells, (3) implementing the pilot wells, (4) analyzing the results from the pilot wells, and (5) applying those results to the rest of the unit.

In this project, team members developed the typical data analysis, reservoir and production engineering proposals, and solutions proposals, and also thoroughly reviewed the customer's economic drivers. In these mature units, enhancing recovery and production rates and reducing costs were important factors.

Treatments have been placed and analyzed for sweep improvement, CO2 reduction, and water cycling-breakthroughs.
Reserve Estimates for Naturally Fractured Reservoirs
Authors: Briggs Arthur R.
Published: December 2007

Reserves estimates in naturally fractured reservoirs present a unique challenge to the reservoir engineer. Reservoir storage capacities and thus reserves in a fractured reservoir come from two major sources: fracture capacity and matrix capacity. Most fractured reservoirs consist of a combination of these two capacities.

Defining area of drainage in a naturally fractured reservoir presents another challenge. Fractures often contribute most of the delivery capacity in a fractured reservoir. Drainage area in a naturally fractured reservoir is oriented along open fracture systems with significant areas included from nearby reservoir rock containing appreciable matrix porosity and permeability and intersected by the fracture system. Horizontal drilling, which is usually oriented in an attempt to intersect several open fracture systems, adds another dimension to the problem of defining area of drainage and delivery capacity.

This paper investigates the application of the major types of reserve estimates including analogy, volumetric, and performance analysis to naturally fractured reservoirs. Sample illustrations and calculations for typical reservoirs will be reviewed and discussed.
Modelling the Productivity of a Multifractured-Horizontal Well
Authors: Cvetkovic' Branimir , Halvorsen Gotskalk , Sagen Jan , Rigatos E. N.
Published: December 2007

The value of horizontal multiple fractured wells can be maximized when the parameters with the greatest effect on productivity of such wells is understood. As a step towards achieving maximum value from horizontal multifractured wells, a computer model (MFHOW) has been developed that allows the user to quickly assess the impact of various well or reservoir properties on well performance. The model is generally three-dimensional and considers full time variability. It assumes single-phase oil flow and is based on semianalytical techniques. The model may be used for modelling transverse or longitudinal fractures of varying type (uniform flux, infinite conductivity, finite conductivity). Flexibility to use various constraints and the option of multi-run sensitivity generation can be used for prognosis of multifractured horizontal well productivity and its diagnosis. The model solution that is developed can be used for general screening and optimization of a multifractured horizontal well because of the fast numerical algorithms implemented. For any given set of reservoir, fracture and well parameters the oil rate, cumulative production, well pressure, or productivity index can be determined. Various model features are presented through sensitivity results and comparison with actual data from a North Sea well.
Studies in Vertical and Horizontal Well-Flow Behavior in Cases of Permeability Anisotropy
Authors: Cline S. B. , Tiab D.
Published: December 2007

Modified 2-phase analytical equation solutions to vertical well behavior match simulated results quite well for fluid flow in both isotropic and highly anisotropic permeability cases above and below the bubble point. Also no matter what the contrast in kx and ky, if the geometric mean permeability was held constant, the simulated rate vs. pressure results were essentially identical to each other. This confirmed the often-used geometric mean permeability approximation. In contrast, analytical solutions to horizontal well flow generally follow simulated solutions in isotropic media but do not match simulated horizontal results very well in horizontally anisotropic permeability conditions. Also horizontal simulations diverge markedly from one another as the permeability contrast increases despite keeping the geometric mean identical. The mismatch is especially pronounced as the x and y directional permeability contrast increases, in cases of pressure above the bubble point and in cases where the well length is large compared to the reservoir dimensions. This behavior is not predicted from standard analytical equations utilizing geometric mean permeabilities.

Extensive simulation experiments allowed construction of graphical relationships that present the effect of increasing degrees of reservoir permeability anisotropy on horizontal well fluid flow as a function of dimensionless well length, reservoir dimension ratios, grid block size and density, reservoir pressure and severities of anisotropy. Despite a constant geometric mean permeability, the flow rate deviation from the isotropic case increases as the degree permeability contrast becomes more severe in the principal x and y directions. The deviation from the isotropic case also increases

as the well length increases for any given reservoir dimension. The deviation is also more apparent as reservoir pressure increases above the bubble point. The number of grid blocks used did not seem to have any appreciable effect on the results.
Geological Parameterization of a Reservoir Model for History Matching Incorporating Time-Lapse Seismic Based on a Case Study of the Statfjord Field
Authors: van Ditzhuijzen R. , Oldenziel T. , van Kruijsdijk C. P. J .W.
Published: December 2007

The geological structure can have a tremendous impact on hydrocarbon flow and, especially in structurally complex reservoirs, is often one of the biggest uncertainties in reservoir modeling. One can think for example, of the sealing capacity of faults or of preferential fluid flow paths dictated by geological bodies. Using geological and structural parameters, these features can be incorporated when history matching a reservoir model. History matching with geologic parameters can enhance reservoir management by identifying non-swept regions and optimizing the placement of infill wells. In this paper we demonstrate an automated history matching method, using geological parameterization. Both time-lapse seismic and production data are used in an integrated manner. The method is tested on a synthetic reservoir, which resembles a structurally complex gravity slide system, common in North Sea reservoirs and other reservoirs situated in similar rift systems. The East Flank of the Statfjord Field is used as an example. The slump and associated faults are characterized by the following parameters: position, size and throw. Results show that the slumps / faults in a structurally complex reservoir can successfully be history matched. Evaluation of the conditioning data shows that the time-lapse seismic data gives more accurate information about the structure than production data.
4D Seismic Monitoring of Water Influx at Bay Marchand: The Practical Use of 4D in an Imperfect World
Authors: Behrens Ronald , Condon Patrick , Haworth William , Bergeron Mark , Wang Zhijing , Ecker Christine.
Published: December 2007

Multiple seismic surveys over time not intentionally designed for 4D evaluation can be used for imaging fluid and pressure changes, and locating bypassed reserves. Bay Marchand is a mature Gulf of Mexico field with a series of stacked reservoirs separated by shale. The first 3D seismic survey was acquired after first production and the second seismic survey was a non-exclusive survey having very different acquisition parameters. These circumstances make interpreting 4D results difficult, but not impossible. We were able to make a reasonable interpretation of the ‘A’ fault block on the original data before cross-equalization although cross-equalization improved the cubes. We were able to identify areas of water influx and areas not yet invaded by water, even though we were prevented from following the typical steps in 4D. Reliability estimates were derived for estimates of saturation change as a function of signal-to-noise ratio and scatter in the rock physics relationships. This paper discusses these steps in contrasting the ideal case with Bay Marchand and show where a 4D project can still be successful even with compromises forced by lack of early data or current budget.

Successful wells have been drilled in the Upper Miocene 7100' and 7600' Sand reservoirs using the 4D results. In the 7100' Sand, the aerial extent of the strong amplitude on the second seismic survey was targeted. This area along the crestal portion of the reservoir was drilled as a secondary target, logged oil, and was subsequently completed with a horizontal well. In the 7600' Sand, the 4D was used as direct evidence of oil saturation. Changes in amplitude were consistent with production from that sand during the time period between the acquisition of the two surveys (1987-1998) but the distribution of oil was not a gravity stable front. Recent sidetracks to two areas with moderate/strong amplitudes on the 1998 survey showed significant remaining hydrocarbons in both areas (one of which is downdip of wells producing with high water cuts). Both of these have been completed as horizontal wells. In spite of the deviation from ideal 4D methodology, the results are useful and are making a business impact.
A New Petrophysically Constrained Predrill Pore Pressure Prediction Method for the Deepwater Gulf of Mexico: A Real-Time Case Study
Authors: Dutta Nader , Gelinsky Stephan , Reese Mike , Khan Mashiur
Published: December 2007

Improper planning and execution of deepwater drilling programs can lead to high costs and unsafe conditions. Proper well planning requires reliable estimates of the expected pore fluid pressure and formation strength prior to drilling. Such pressure predictions are based on integrated seismic and offset well data. A new, rock model-based approach especially suited for deepwater pore pressure imaging is introduced here and applied in an example of a deepwater Gulf of Mexico well. P- and S-velocities were determined both at an offset well and for the future drilling location, using prestack seismic full waveform inversion. Both predicted velocities were later verified with log measurements. Using the new model, a significant pore pressure increase at depth was predicted before drilling the well and verified while drilling (Figure 1). For the entire well, the predicted and measured pore pressure gradients agree within half a pound per gallon equivalent mudweight (Figure 1). The shear velocity, and the extracted shear modulus, proved to be excellent indicators of low effective stresses, corresponding to overpressured formations (Figure 2).
Lessons Learned in the Planning and Drilling of Deep, Subsalt Wells in the Deepwater Gulf of Mexico
Authors: Whitson Charles D. , McFadyen Michael K.
Published: December 2007

As more deepwater wells in the Gulf of Mexico (GOM) are being drilled for subsalt objectives, salt sections in excess of 6,000 ft. and well depths in excess of 25,000 ft. are becoming common. In order to drill these wells successfully, deepwater operators are required to focus planning efforts on the challenges posed by these extreme salt sections and well depths. Texaco recently planned and drilled two such wells in the Walker Ridge Area of the GOM. Both wells had salt bodies in excess of 10,000 ft. and were planned with total depths below 26,000 ft. The advantages of long salt sections are (1) high fracture gradients within the salt, which allows longer hole sections between casing strings and (2) insulation from typical well control problems associated with permeable formations. Disadvantages include (1) difficulty in predicting the pore pressure and fracture gradient in the sedimentary section below salt and (2) hole deviation and related directional control problems in the salt.

During the planning of these wells, drilling personnel focused on (1) the drilling of non-under-reamed hole sizes in salt for enhanced directional control, (2) use of new technology to increase ROP and directional control in the salt, (3) installation of heavy, longstrings of casing demanded by the long salt sections and (4) formation of contingency plans to account for the uncertain subsalt pore and fracture pressures. This paper outlines the approach taken in the planning of the two wells and discusses the lessons learned during the execution, most significantly: (1) long salt sections can be used to advantage to extend casing points and eliminate well control issues, (2) ROP in salt can be maximized through the use of conventional, non-under-reaming bits, stabilized bottomhole assemblies, and synthetic oil based mud, and (3) a detailed planning and quality control program is required for the successful running of heavy longstrings of casing.
Pump-in/Flowback Tests Reduce the Estimate of Horizontal in-Situ Stress Significantly
Authors: Raaen A M , Brudy M
Published: December 2007

This paper presents field data from pump-in/flowback tests at different locations offshore Norway, illustrating that standard extended leak-off tests (XLOTs) in tight formations may overestimate the minimum horizontal in-situ stress by at least 20 bar, corresponding to 0.1 s.g. at 2000m.

The pump-in/flowback test is a simple variant of an XLOT. After the shut-in period, fluid is allowed to flow back over a fixed choke, and the pressure and the returned volume are recorded as a function of time.

We compare results from several pump-in/flowback tests to the results of the conventional pump-in/shut-in method used for XLOTs. For the tests presented here, performed in tight formations, the true fracture closure pressure is shown to be up to 20 bar lower than what would be inferred from a traditional interpretation of the standard XLOT.

It is argued that the pump-in/flowback test in a majority of cases will be straightforward to interpret, and that it should hence be the preferred method for measuring the minimum horizontal in-situ stress.
A Quantitative Investigation of the Laminar-to-Turbulent Transition: Application to Efficient Mud Cleaning
Authors: Brand Fabien , Peixinho Jorge , Nouar Cherif
Published: December 2007

Spacer and wash fluids play an essential role in the cementing of oil and gas wells. They are pumped ahead of the cement to optimize the mud displacement, enable a proper hole cleaning, and obtain a good cement bond at the formation and the casing surfaces.

The design of spacer fluids relies on an ensemble of physical and chemical characteristics of the spacer including flow characteristics (rheological properties), the stability of the weighted spacer suspension, and the compatibility with other wellbore fluids.

The flow characteristics of spacer fluids are the key to successful cementing. The wellbore fluids pumped in the field usually behave as viscoplastic fluids. The non-Newtonian nature of these fluids must be accurately modeled when determining the flow behavior around a centered or eccentric annulus to accurately determine flow regime and dynamic pressures in the annulus along the entire column of fluid.

Turbulent flow is the preferred flow regime for efficient mud removal in the annulus, provided the cleaning fluid is effectively in turbulent flow all around the eccentered annulus. Therefore, a reliable criterion for the critical Reynolds number is needed to properly design the well-cleaning process and determine whether it is feasible to be in turbulent flow.

In an effort to better understand the fluid dynamics involved with mud cleaning, we have conducted an experimental study on a series of spacer and model fluids. Axial velocity and relative fluctuation intensity measurements were conducted using three different techniques: (1) ultrasonic Doppler technique, (2) hot film anemometry, and (3) laser Doppler velocimetry. On the basis of these results, we have been able to fully characterize the laminar-to-turbulent transition and evaluate the pressure drop caused by highly non-Newtonian fluid. The results of this study help us define more reliable estimates of the minimum pump rate that will lead to substantial well-cleaning efficiency, taking into account the rheological behavior of non-Newtonian fluids.
Well Cementing Diagnosis from Top Cement Pulsation Record
Authors: Kunju Mahendra R. , Wojtanowicz Andrew K.
Published: December 2007

The paper reports on a feasibility study on post-cementing quality control using recorded data from Top Cement Pulsation (TCP). TCP is a novel technique for preventing gas flow after cementing. In this method small hydraulic pressure pulses (usually 100 psi.) are applied repeatedly at the surface into the casing annulus starting immediately after cement placement until the end of the cement transition time. The volumes of water pumped into the annulus and returned during TCP is monitored and converted to Top Cement Displacement Record (TCDR). These short duration pulses make the slurry columns shear and fluidize. The fluidization prevents under balance-a primary cause of gas migration after cementing.

It had been postulated that TCDR might provide valuable information on the quality of cement setting in the annulus of the well. Consequently the record should some how be analyzed to determine fluid loss volume, initial/final position of top of cement and identify problems such as high fluid loss, bridging; identify presence of high temperature zones.

The paper presents a diagnostic method based on recognition of TCDR patterns. From mathematical modeling of pulse transmission, different characteristic patterns have been derived. In the method the TCDR recorded from actual TCP data is compared with the expected TCDR. Then, a difference in the TCDR pattern between the expected and the actual TCDR is analyzed. From the analysis it can be determined what might have happened to the fluids placed in the annulus.

Also included in the paper is validation of the diagnostic technique using field data collected from wells subjected to TCP. The wells were having relatively long interval of open hole with cement top far below the previous casing shoe. From the analysis it was possible to verify the progressive shearing of fluid columns during each pulse, the rate of fluid loss, the zone of fluid loss, end of cement thickening period, and top of cement.
Application of Ilmenite as Weight Material in Water Based and Oil Based Drilling Fluids
Authors: Saasen A. , Hoset H. , Rostad E. J. , Fjogstad A. , Aunan O. , Westgård E. , Norkyn P. I.
Published: December 2007

In field operations from a semi-submersible rig offshore northern Norway, ilmenite has been used as weight material in the drilling fluid. From environmental considerations, it has been desirable to exchange barite with ilmenite to minimise the discharges of heavy metals while drilling with water based drilling fluids. Field trials during the eighties and early nineties have shown that use of ilmenite as weight material can cause severe erosion problems. By adjusting the particle size distribution of the ilmenite to a narrow cut with the particle mean size around 10 micron, the erosion was brought down to a level generally underneath the erosion level experienced when drilling with barite.

The paper describes in detail the effect of ilmenite and barite onto erosion of surface lines and manifolds connected to the bulk system, mud mix-, transfer- and supercharge pumps, and mud pump. The erosion of these pipes was reduced when using ilmenite in water based drilling fluids. In oil based drilling fluid there were not observed any significant erosion when using either weight materials. The change in wear on the mud pump pistons and liners will be outlined. Furthermore, the impact the different weight materials have on the erosion of Measurement While Drilling equipment (MWD) will also be outlined. It is also shown that a reduction in rig air pressure for transporting ilmenite in the bulk handling system has reduced the erosion in the exposed bulk pipelines. Finally, the consequences for running the drilling fluid operation are presented.
Farmout Valuation Using Exotic Real Options
Authors: Rutherford Steven R.
Published: December 2007

This paper describes a Real Options evaluation of a real-world farmout opportunity in case history format. The Real Options evaluation utilizes exotic options (standard barrier option and cash-or-nothing binary options) borrowed from the financial community and adapted for use in Oil and Gas economic valuations. A Delineate/FO option is constructed to address the question of whether a marginal discovery should be farmed out immediately or be delineated and then farmed out if hurdle reserves are not achieved

The result of the evaluation is that the marginal discovery should be delineated. The option value associated with the upside reserves potential and the ability to farmout the project should the upside not be realized more than offsets the cost of the option (cost of the delineation program). Hence, delineating and maintaining the option to farmout later enhances total project value. The real options approach to valuing the project is also contrasted with a conventional DCF valuation that gives little insight on the farmout question.
A Discussion on the Impact of Information Technology on the Capital Investment Decision Process in the Petroleum Industry
Authors: Back Michael J.
Published: December 2007

Advances in information technologies have pushed key E&P decision-makers to process greater amounts of data and information before making important capital investment decisions. The corporate planner is faced with an increasingly difficult task as the number of opportunities and the data associated with them has grown exponentially. The capital investment decision process demands greater speed and efficiency than ever before. Traditional capital investment planning and acquisition/divestiture work involved sorting through physical data rooms of seismic, production and economic data stored in a variety of paper copy and digital formats. The introduction of affordable high-bandwidth networks and fast data processors has allowed on-line data rooms, powered by application service providers (ASP) and web portals, to bring petroleum acquisition and divestiture to the desktop computer. Corporate and financial planners are able to employ increasingly advanced database and decision analysis software solutions to vastly improve the quality control and the speed of the investment decision process. Integrated software for real-time reservoir modeling, precise economic calculations and efficient portfolio optimization of diverse sets of exploration and production opportunities has become a reality.

This paper will review the evolution of the capital investment decision process from the traditional corporate planning workflow to the latest application of software dedicated to reservoir data processing and economic analysis of world petroleum fiscal regimes. The ability to apply portfolio management techniques using sophisticated mathematical search and optimization algorithms to greatly increase the efficiency of the planning process will be explored. This paper will discuss the key success factors associated with the capital investment decision-making process in the E&P industry and will use a personal computer to analyze a set of oil and gas assets on-line in the context of choosing an optimal corporate portfolio.
Knowledge Management at Kuwait Oil Company: PeopleLink – Mobilizing Expertise Using Intranet Technology
Authors: Al-Abbasi Adel , Chapman Terrance
Published: December 2007

Kuwait Oil Company, in its initial approach to employing knowledge management principles across the enterprise, developed an intranet website for employees to publish details of their expertise and examples of their work. PeopleLink was concieved and created in less than a year, winning a Microsoft award on the way.
Poromechanical Tools for Reservoir Rock Testing Simulation and Wellbore Stability
Authors: Abousleiman Y. , Kanj M. , Ekbote S.
Published: December 2007

In the past decade, the applicability of the poromechanics theory in the oil and gas industry has taken big strides. Many of the mathematical complexities encountered with time-dependent coupled processes in rock/fluid interaction have been overcome. The coupled phenomena associated with the rock matrix deformation, fluid flow, temperature gradients, and chemical activity have been modeled in an analytical form. And the various analytical solutions related to rock testing and wellbore stability simulations have been implemented in two industry-supported software tools: PCORE-3D and PBORE-3D. On the one hand, PCORE-3D is intended for simulating and analyzing laboratory rock testing. On the other hand, PBORE-3D is targeted at predicting and designing wellbore stability during drilling.

Both packages are modeled within the frameworks of the time-dependent coupled theories of poromechanics as well as the classical theory of solid mechanics. The design engineer, thus, is capable of comparing solutions of the specific problems, within the realm of these theories. In this study, the solutions to the subject problems are explained with illustrative emphasis on laboratory and field cases; the mechanical interpretation of the output is cognitively elaborated; and both software tools are fundamentally described in details with their respective 3-D monitoring capabilities illustrated.
Application of Plasma Technology to Fracture Tight Formations
Authors: El-Naas Muftah , Zekri Abdulrazag Y.
Published: December 2007

Tight formations are normally fractured using different fluids under high pressure to improve well permeability and consequently improve productivity. In this paper, a new sophisticated technique is proposed to treat tight formations, especially those containing large deposits of heavy oil. The technique consists of exposing the wellbore to an argon plasma jet to insure instantaneous and efficient heat transfer to the surrounding wellbore rocks. The high temperature associated with the plasma jet changes the basic properties of the rock resulting in a significant increase in its porosity and permeability. In this study the effect of high temperature on the carbonate rock porosity and permeability is investigated. Limestone rocks were subjected to high temperatures ranging from 800 to 1200 °C. At temperatures beyond 600 °C, the carbonate rock decomposes to form calcium oxide and carbon dioxide. TGA analysis of carbonate samples indicated that the rate of decomposition at atmospheric pressure depended mainly on reaction temperature. At low temperatures, the rate of reaction was so slow that only 5% of the carbonate converted to calcium oxide in a period of one hour, while at 1000 °C complete conversion was achieved in five minutes. The changes of the pore structure under different temperatures were also observed using Scanning Electron Microscope (SEM). Porosity & permeability analysis of heated carbonate samples indicated that the porosity and permeability increased by 100% and 4500 % respectively at 1000 °C.
Treatment of Produced Water Utilizing Ceramic Technology: Field Trail
Authors: Buarki M. I. , Tabtabai I. , Hatabata H. , Konishi Y.
Published: December 2007

"Edena-I" is a pilot plant designed to utilize a noble Continuous and Amorphous Pore Surfaces (CAPS) ceramic technology for the treatment of first stage desalter effluent. It is made up of four connected tanks, three of which are charged with CAPS ceramic. Edena-I was operated in the great field of Burgan, Kuwait, over a period of five continuous months. The design objective of Edena-I was the removal of dispersed oil, which was met without difficulties. Results of dispersed oil concentration for inlet samples were in the range of 1.0-4,800 ppm while outlet samples were almost always below 5.0 ppm. At the last week of the trail, samples were submitted for the determination of Oil & Grease and Chemical Oxygen Demand (COD). Oil & Grease concentration of inlet samples ranged from 6,000 up to 500,000 ppm, while outlet samples had a concentration of 20-40 ppm. The difference in COD results of inlet and outlet samples demonstrates 83-89% COD treatment efficiency. Such results give a strong indication that different types of treatment are carried out by CAPS ceramic. It is the conclusion of this paper that CAPS ceramic technology should be further investigated as a potentially viable alternative technology in the field of Produced Water treatment.
Direct Measurement of Dynamic Relative Permeability from CT Monitored Spontaneous Imbibition Experiments
Authors: Schembre J. M. , Kovscek A. R.
Published: December 2007

A novel method for computing two-phase relative permeability curves from the results of spontaneous imbibition experiments is presented. Using a specially constructed imbibition cell and an X-ray Computed Tomography (CT) scanner, we obtain accurate measurement of saturation profiles along the length of cores as a function of time. The saturation profile history allows direct computation of the relative permeability for both phases from a single experiment when used in combination with a previously measured capillary pressure curve. Results are unique within experimental error. The proposed procedure works equally well for spontaneous and forced cocurrent imbibition. It was tested thoroughly using synthetic and experimental data, for water-air and water-oil systems. Test results are described within the paper. Advantages include the incorporation of capillary forces and no requirement for steady-state conditions. This method is useful to measure imbibition relative permeability curves, especially in low permeability rocks. In such systems, it is laborious to reach multiple steady states and capillary forces are significant so that classical unsteady-state techniques do not apply.
Interfacial Effects in Gas-Condensate Recovery and Gas Injection Processes
Authors: Meleán Y. , Bureau N. , Broseta D.
Published: December 2007

Gas condensate production and gas injection processes are strongly influenced by the gas/oil (or condensate) interfacial tension and by the wetting behavior of oil on the porous substrate. Oil (condensate) recovery is favored by low gas/oil (condensate) interfacial tensions and by complete wetting of oil (condensate) on the water phase that often covers the porous rock. The relevant parameters are dimensionless numbers that measure the importance of the oil/gas interfacial tension relative to gravity (Bond number) and to viscous (capillary number) forces. Another important parameter is the oil/gas contact angle on the water that often covers the porous substrate: a zero contact angle corresponds to complete wetting of oil, while a finite angle corresponds to partial wetting. These parameters are increasingly used in modern reservoir simulators for estimating oil and gas residual saturations and relative permeabilities.

We analyze how these parameters vary with the operating conditions (e.g., pressure) and the nature of the injection gas: CH4, CO2 and N2. On approach to gas/oil complete miscibility, both the capillary and Bond numbers diverge, i.e., viscous and buoyancy forces dominate over capillary forces. For nearmiscible conditions, these numbers obey simple scaling laws as a function of the distance to complete miscibility. The prefactors of these scaling laws depend on the particular oil+gas system, which allows to classify the efficiency of the different injection gases. For reducing capillary forces with respect to the viscous or buoyancy forces, supercritical CO2 is more advantageous than off-critical CO2 or CH4, which themselves are more advantageous than N2.

We also present a simple calculation scheme for predicting the conditions under which the transition to complete wetting of oil on water occurs, i.e., the oil/gas contact angle vanishes. The only ingredients needed are the composition and densities of the three coexisting phases (water, oil and gas), calculated by means of an appropriate equation of state. The essential result is that under typical operating conditions, oils or condensates spread on water, the transition to partial wetting being remote from complete miscibility conditions. CO2 is the most effective in promoting the wetting (or spreading) of the oil phase on water, followed by CH4 and then by N2.
Thickening Carbon Dioxide with the Fluoroacrylate-Styrene Copolymer
Authors: Xu Jianhang , Enick Robert M.
Published: December 2007

The fluoroacrylate-styrene copolymer, polyFAST, is the first associative thickener that has been identified for carbon dioxide. Fluoroacrylate is highly carbon dioxide-philic, enhancing the solubility of polyFAST in carbon dioxide. Styrene is relatively carbon dioxide-phobic, but promotes viscosity-enhancing, intermolecular associations. The polyFAST copolymer used in this study had a composition of 29 mol% styrene - 71 mol% fluoroacrylate, a number-average molecular weight of 540,000 and a polydispersity index of 1.63. Carbon dioxide density values of 0.65-0.85 g/cc were required to dissolve 0.25-2.0wt% polyFAST in the 298 – 373 K temperature range. Falling cylinder viscometry measurements at 298 K demonstrated that the viscosity enhancement of CO2 associated with polyFAST increased with increasing polyFAST concentration, decreasing shear rate and decreasing temperature. The non-Newtonian falling cylinder viscometry results at 298 K were fit to a power law model with copolymer concentration-dependent coefficients. Mobility measurements of polyFAST-CO2 solutions flowing through 80-200 md Berea sandstone cores at superficial velocities of 0.00035 – 0.028 m/s (1 - 80 ft/day) at 298 K also indicated that polyFAST was an effective thickener. At a superficial velocity of 0.00035m/s (1ft/day), 1.5wt% polyFAST increased the CO2 viscosity by a factor of 19 relative to neat CO2. Smaller increases in viscosity occurred at lower polyFAST concentrations and higher velocities.
An Effective Continuum Model for the Liquid-To-Gas Phase Change in a Porous Medium Driven by Solute Diffusion: I. Constant Pressure Decline Hates
Authors: Tsimpanogiannis Ioannis N. , Yortsos Yanis C.
Published: December 2007

We derive an effective continuum model to describe the nucleation and subsequent growth of a gas phase from a supersaturated, slightly compressible binary liquid in a porous medium, driven by solute diffusion. The evolution of the gas results either from the reduction of the system pressure at a constant rate. The model addresses two stages before the onset of bulk gas flow, nucleation and gas phase growth. We assume negligible gradients due to gravity or viscous forces, thus the critical gas saturation, which signals the onset of bulk gas flow, is only a function of the nucleation fraction.

We show that the important quantities characterizing the process, such as the fraction of pores that host activated sites, the deviation from thermodynamic equilibrium, the maximum supersaturation in the system and the critical gas saturation depend crucially on the nucleation characteristics of the medium. We use heterogeneous nucleation models primarily in the form of pre-existing gas, trapped in hydrophobic cavities, but also in terms of a rate-dependent nucleation, to investigate in detail the nucleation behavior. Using scaling analysis and a simpler analytical model we show that the relevant quantities during nucleation can be expressed in terms of a simple combination of dimensionless parameters, which include rate effects, for either type of nucleation model.

The theory predicts that the maximum supersaturation in the system is a weakly increasing function of rate, which in the region of typical experimental parameters, can be approximated as a power law with a small exponent. This function depends sensitively on the probability density function of the nucleation cavity sizes. It also predicts that the final nucleation fraction, thus the critical gas saturation, is a power law of the decline rate. The theoretical exponents are shown to be in good agreement with experimental data. The subsequent evolution of the gas phase and the approach to the critical gas saturation is also described.
MRI Tomography of Saturation Development in Fractures During Waterfloods at Various Wettability Conditions
Authors: Graue A. , Aspenes E. , Moe R. W. , Baldwin B. A , Moradi A. , Stevens J. , Tobola D. P.
Published: December 2007

At three different wettabilities, two stacked outcrop core plugs, separated by a 1 mm fracture, were waterflooded. During the experiment in-situ fluid saturations were monitored with Magnetic Resonance Imaging (MRI). The sequence of 2D MRI images corroborated earlier lower resolution, larger scale experimental results on the effect of fractures during waterflooding at various wettabilities. The MRI images of oil saturation development in the fracture clearly revealed two distinct transport mechanisms for the wetting phase, water, across the fracture at several wettability conditions.

When strongly-water-wet, the first core reached its spontaneous imbibition endpoint before water left the matrix and entered the fracture. The displaced water flowed down the exit face to the bottom of the fracture and displaced the oil upward at the rate of water injection. At less-water-wet conditions water droplets formed on the exit face of the first plug and grew large enough to form individual bridges between the two plugs. This happened well before the first plug reached its spontaneous imbibition endpoint. Under these conditions, the fracture filled slowly, as the bridges increased in diameter and additional bridges formed. Due to the capillary continuity of the wetting phase, a viscous pressure drop was established across the stacked core plugs, providing a viscous component to the total oil recovery.
Background and Operational Experience of Multiphase Metering in the Safaniya Field-Offshore Saudi Arabia
Authors: Warren P. B. , Hussain S. , Ghamdi S.
Published: December 2007

An automated and compact multiphase flow meter (MPFM) tested offshore Saudi Arabia has accurately measured three - phase flow rates under existing field operating flow conditions. An extensive eight-month field test in the Safaniya field was conducted from October 1999 to June 2000 utilizing over 350 well tests under varying operating conditions. A meter was installed on an offshore test barge, so that individual wells could be tested in series with traditional test barge methods. For these trial tests, the total liquid rate ranged from 1300 to 12000 barrels per day, the GOR ranged from 150 to 350 SCF/STB and the water cut ranged from 0 to 50%. The results show that over 90% of the wells tested were within +/− 10% of test barge results for all liquid, oil and water cut measurements. While gas measurements were determined to be within +/− 15% in 75% of the wells tested.

As a result of this favorable field test and other economic considerations, a multiphase flow meter is recommended for installation on all Safaniya Field existing offshore platforms. Project installation designs for the first five meters have been completed and plans are being made to install them beginning in early 2002.
Global Optimization of Oil Production Systems, A Unified Operational View
Authors: Vázquez Manuel , Suárez Alexis , Aponte Hugo , Ocanto Leonardo , Fernandes José
Published: December 2007

Oil production systems (OPSs) are complex and heterogeneous. They comprise several equipment and their wells flow naturally or using a variety of artificial lift methods. To optimize these systems, integrated multidisciplinary skilled teams managing a considerable volume of information are required. In practice, OPSs are not optimized globally; instead some subset of the system is optimized locally or many simplified assumptions are used which may not be consistent with the OPS conditions. For example, artificial lift wells are tuned according to their completion and surface facilities without considering the rest of the system. Traditional optimization techniques such Linear and Dynamic Programming, available from the Operation Research (OR) community, fail to find a global optimum solution for this problem or demand a considerable amount of computational resources making impractical their application. Under these techniques, an objective function has to be stated precisely and has to cover all the variables to optimize, being necessary a strong mathematical and OPS knowledge. This paper presents a new methodology for global optimization of OPSs. We developed an optimization procedure merging Artificial Intelligence (AI) techniques with OR techniques to deal with this problem. Combining the power of evaluating alternative solutions and flexibility of Genetic Algorithms (GAs) with the local search abilities of the Tabu Search (TS) meta-heuristic, a robust solution is found requiring a reasonable amount of computational resources. The OPS manager can easily change the objective function, only the optimization target is requested, and the performance of our technique is not affected. Through this objective function and our OPS model, the OPS is unified under economical or operational criteria. Our method is being tested on 25 wells OPS combining SRP, PCP and ESP wells. A 5% of increase in oil production and a 10% of reduction in energy consumption is expected.
Transient Well Index for Numerical Well Test Analysis
Authors: Archer Rosalind A. , Yildiz Tabiat T.
Published: December 2007

Incorporating well test data into integrated reservoir characterizations may require the well test to be modeled in a reservoir simulator that also forward simulates other dynamic data being matched. Care is required to ensure the simulator is not introducing unnecessary numerical artifacts. Standard finite-difference reservoir simulators use the Peaceman well index, which is based on the solution to single-phase, steady-state, incompressible flow. For a pressure transient test the assumptions of steady-state, incompressible flow are not applicable. However instead of modifying the well index it is common to account for this by using highly refined grids around wells and making very careful choices of timestep sizes to model well tests.

This work presents a new well index formulation that allows well tests to be simulated accurately in finite-difference simulators using uniform, relatively coarse grids, without the problem of artifact wellbore storage (early time unit slope on the pressure derivative only) that otherwise occurs. The well index model computes the average pressure in the well block directly from the analytical solution for infinite acting radial flow. This approach can also be applied to non-square gridblocks and anisotropic reservoirs.

Well tests simulated using finite-difference simulation with the proposed transient well index and the Peaceman well index are compared to analytical well test solutions. The simulated well tests using the proposed transient well index closely follow analytical solutions – even on coarse grids (e.g. 15 cells by 15 cells, 167 feet by 167 feet). When the same simulations were performed using the Peaceman well index, the simulated pressure transients showed significant artifact wellbore storage, especially in low permeability reservoirs.