bluuebunny/crossref_metadata_2025_split huggingface dataset:
Using Optical Fluid Analysis To Evaluate Downhole Fluid Sample Contamination
Authors: Morris C.W. , Felling M.M. , Butsch R.J. , Sass W. 
Published: December 2007

Abstract
Wireline formation testers are commonly used to obtain fluid samples and measure formation pressure during openhole logging operations. The identification of the fluid usually depends on the analysis of the sample chamber contents at the surface. A new approach is now possible using the measurement of in-situ optical fluid density. This analysis can be used to determine the formation fluids and to evaluate significant fluid characteristics in real time.
The optical fluid analysis technique utilizes a visible and near-infrared absorption spectrometer for fluid discrimination and a refractometer for free gas. The spectrometer measures the transmittance of a liquid at 10 different wavelengths and distinguishes between oil and water by comparing the resulting absorption spectra in the visible and near-infrared region. The spectrometer yields quantitative data on fluid phase volumes and qualitative data concerning fluid coloration. Experiments were performed to catalog the optical fluid density characteristics of typical hydrocalbons, formation waters, filtrates, drilling mud systems, and mixtures of these fluids.
Utilizing this data base, optical density measurements can do an excellent job differentiating between oil and water. Hydrocarbon responses also show a strong correlation trend with optical fluid density measurements and can be used to estimate the in-situ oil gravity. Furthermore, differentiation between oil~base drilling fluid filtrates and hydrocarbons is possible. This outcome was observed with diesel, synthetic oil, and various other oil-base filtrates.
A new technique has been developed, which performs a weighted regression analysis on the optical spectrum, to quantify the mud filtrate contamination, water, and formation hydrocarbon in real-time. Field examples are presented to illustrate the application of the optical density information to the interpretation of formation fluid characteristics. The technique reduces overall sampling time, minimizes sample contamination, and improves sample quality.
P. 283
T2 Relaxation Time Versus Mercury Injection Capillary Pressure: Implications for NMR Logging and Reservoir Characterisation
Authors: Lowden Benjamin D. , Porter Matthew J. , Powrie Linda S. 
Published: December 2007

Abstract
A link between distributions of T2 relaxation time and capillary pressure curves has been demonstrated in several articles published over the last few years. Efforts to establish a link have mostly concentrated on high pressure air/mercury experiments (MICP). Establishing a link between T2 and MICP is important because it adds confidence to estimates of bound fluid, free fluid, and permeability from NMR logs. The link also provides another route to saturation height functions. However, experience working with NMR logs has shown that estimates of bound fluid are frequently under or overestimated and the default parameters used to determine bound fluid (e.g. T2 cutoffs) have to be adjusted to compensate for this. Often, little is known about how these adjustments relate to the actual pore system.
Analysis of 176 core samples representing a broad spectrum of sandstone reservoirs demonstrates the link between T2 and MlCP is unpredictable. This result challenges use of simplistic pore models for predicting bound fluid and explains why bound fluid estimates from NMR logs are often wrong. However, there is sufficient similarity between data sets for T2/Pc functions to be developed locally from core on a well-by-well basis. These functions can be applied to NMR logs using a process of pattern recognition which identifies similar NMR response type's within logs and core samples. NMR response types and their associated T2/Pc function provide information about upscaling and flow units.
P. 323
Multiple Fracture Stimulations In Horizontal Open-Hole Wells The Example of Well Boetersen Z9, Germany
Authors: Kamphuis H. , Aretz R. , Nitters G. , Loidl H. 
Published: December 2007

Abstract
The hydraulic fracturing of uncased wells or wells completed with a pre-drilled liner carries a risk of early proppant screenout. On the other hand, this can be a very cost-effective completion and stimulation method. This paper describes the successful application of multiple hydraulic fracturing in a deep horizontal gas well, Boetersen Z9, which was completed with a pre-drilled liner.
The first step in the design of the treatment was to determine the optimum positions of two propped fractures with information from a production log and from multifrac inflow simulations. Weakening the rock by perforating would raise the probability that two hydraulic fractures would he created at these positions during fracturing. The actual positions of the fractures were later estimated from the minifrac analysis. The main pumping treatment was an extension of common practice. Pump rates were maximized so several fractures could grow simultaneously to the planned length and width. A large stage with medium proppant loading was pumped to confirm access to the fractures before stages with higher proppant loadings were pumped. Precise stage volumes were inferred from the minifrac and took into account the uncertainty in the actual positions of the fractures. Resin-coated proppant was used throughout the job, rather than being used as a tail-in only, because fractures could become packed off at any time during the job and proppant flowback is avoided for each of them.
The well capacity increased from 7000 m3/h at 100 bar FWHP to 20000 m3/h at 370 bar. Skin and good communication between the fractures and the open-hole wellbore may have contributed to the success of the treatment.
P. 351
Effective Algorithm for Calculation of Minimum Miscibility Pressure
Authors: Jessen Kristian , Michelsen Michael L. , Stenby Erling H. 
Published: December 2007

Abstract
This paper describes a new algorithm developed for calculation of the minimum miscibility pressure (MMP) for the displacement of oil by a multicomponent injection gas. The algorithm is based on the key tie line identification approach initially studied by Wang and Orr. A new global formulation is introduced to describe and locate the sequence of nc- 1 key tie lines controlling the development of miscibility. In this new formulation, a number of numerical weaknesses of the original approach have been eliminated resulting in a robust and highly efficient algorithm. The computation time is reduced significantly and is clearly superior to other methods described in the literature. For a 15 component fluid description the MMP is determined within a few seconds on a PC. Hence the algorithm offers an efficient tool for projects where a large number of MMP calculations are needed (e.g. lumping and gas enrichment studies).
A case study is presented based on a real reservoir fluid for which PVT studies, swelling test and slimtube experiments have been performed. The study aims at investigating the influence of the characterization, tuning and lumping procedure used for generating a fluid description on the prediction of the MMP.
Based on the generated fluid description, a gas enrichment study is presented where the optimum mixture of two available injection gasses is determined aiming to optimize the gas injection project.
P. 559
Curvilinear Local Grid Refinement
Authors: Ghosh S. 
Published: December 2007

Abstract
A local orthogonal curvilinear coordinate system is used for Local Grid Refinement (LGR) of rectangular wellblocks in a finite difference grid. The refinement is hybrid since the curvilinear well-subgrids are approximately radial close to wells, while approximately rectilinear near wellblock boundaries. A composite of a local stretching and a conformal transformation is used to map individual wellblocks onto the unit disk on the complex plane. The pre-image of a radial grid on the complex plane becomes an orthogonal curvilinear grid on a k-isotropic real plane, centered at the well. The method allows us to avoid use of a numerical correlation for effective wellblock radius, and the associated limitations of the conventional Peaceman well model no longer apply.
Radial gridblock centers on the complex plane can be distributed logarithmically. This allows for an optimum spacing of gridblocks, and is a major advantage over Cartesian near-well LGR.
For the well-subgrids, curvilinear gridblock pore volumes are obtained by a numerically inexpensive integration on the complex plane. The details of the numerical methods that make pore volume determination rapid and viable for realistic field-scale simulations, will be presented elsewhere. Inter-block transmissibilities, half-boundary transmissibilities and well indices are obtained from an analytic potential for radial flow on the unit disk. This scheme is both more accurate and less cumbersome than those based on curvilinear grid geometry. Furthermore, the determination of gridblock centers on the real plane becomes unnecessary.
The hybrid nature of the well-subgrids reduces grid discretisation errors near wellblock boundaries. The method easily accommodates k-anisotropy and off-centered wells. For multi-phase problems, when near-well gridblocks become small the fully implicit solution technique is applied to the well-subgrids, while an implicit pressure, explicit mass (IMPEM) technique is applied to the parent coarse grid.
Owing to orthogonality, adding curvilinear LGR capability does not require extensive reprogramming of a five-point (on the plane) finite difference simulator. This is important from a practical standpoint. The present curvilinear LGR formulation has been integrated into a general purpose full-field finite difference simulator (with existing Cartesian LGR capability) without any reprogramming of the simulator kernel.
The method applies to well regions comprising several coarse gridblocks in the vicinity of wells, provided these well regions do not have areally varying k-anisotropy. Extensions to polygon well regions are also possible, making the method applicable to cornerpoint or general flexible grids. This enhancement is only outlined in this paper.
Several applications have been chosen to demonstrate the potential of curvilinear LGR. Comparisons are also made between curvilinear and Cartesian near-well LGR.
P. 29
Petroleum Reservoir Simulation Coupling Flow and Deformation
Authors: Cuisiat F. , Gutierrez M. , Lewis R.W. , Masters I. 
Published: December 2007

Abstract
The paper presents a discussion on the issues related to the interaction between rock deformation and multiphase fluid flow behaviour in hydrocarbon reservoir simulations. Pore pressure and temperature changes resulting from production and fluid injection induce rock deformations which should be accounted for in reservoir modelling. Reservoir rock deformation can affect the permeability and pore compressibility of the rock. In turn, the pore pressures will vary due to changes in the pore volume. The deformation of the surrounding non-reservoir rocks (under-, side- and over- burdens) should also be taken into account in order to assess their effects on the overall reservoir compressibility as well as the loads transmitted to the reservoir by the weight of the overburden.
The paper presents the formulation of Biot's equations for multi-phase fluid flow in deformable porous media. Based on this formulation, it is argued that rock deformation and multi- phase fluid flow are fully-coupled processes which should be accounted for simultaneously. However, the coupled equations can be decoupled to a classical hydraulic diffusivity equation for pre-defined simple stress paths. In the general case, by contrasting Biot's equations and its finite element discretization to the corresponding multiphase fluid flow equations used in classical reservoir simulations, it is shown that reservoir simulators neglect or simplify important geomechanical aspects that can have impact on reservoir productivity. This is attributed to the fact that the only rock mechanical parameter involved in reservoir simulations is the pore compressibility. This parameter is not sufficient in representing aspects of rock behaviour such as stress path dependency and dilatancy, which require a full constitutive relation. Furthermore, the pore pressure changes due to the applied loads from the non-pay rock cannot be accounted for by simply adjusting the pore compressibility. Example problems are shown in order to illustrate the importance of coupling flow and deformation in reservoir simulators.
P. 63
Brage Field, Lessons Learned After 5 Years of Production
Authors: Lien S.C. , Lie S.E. , Fjellbirkeland H. , Larsen S.V. 
Published: December 2007

Abstract
The Norwegian North Sea Brage field is currently on decline from its plateau oil rate of 19 400 std m3/d. This paper summarizes five years of production experience from the two highly different reservoirs that have been developed so far.
The fluvial, Lower Jurassic Statfjord formation consists of 1000 to 4000 md sandstone reservoir, with excellent vertical and lateral communication properties. A recovery of approximately 64% is expected from waterflooding the highly undersaturated 36 API oil.
The shallow marine Fensfjord formation, of Middle Jurassic Age, is a stratified sandstone reservoir with average zone permeabilities in the range of 1 to 200 md. Calcite layers and high permeability strikes, with up to 5000 md permeability, amplify the heterogeneity and complexity of this reservoir. The oil has similar properties as in Statfjord, but a recovery of only about 32% is expected. The principal recovery mechanism is aquifer support aided by water injection from the flanks.
The initial Fensfjord development was based on vertical wells with perforated cemented liner. Early production experience proved sand production to be a major problem. To avoid sand production, two wells were hydraulically fractured with proppants. This concept has later been left in favour of horizontal wells with sand screen, sliding sleeves and external casing packers (ECP's).
New water injection wells are horizontal. In these wells the horizontal section is divided into two parts: the toe part is completed with a sand screen and accessed through tubing; the heel part is a perforated liner and accessed through the annulus. In this way the two parts can be controlled as two individual injectors. An additional benefit is the possibility of producing oil from the toe part of the well while at the same time injecting in the annulus section.
A water-alternating-gas (WAG) injection pilot was established in the Fensfjord reservoir in 1994. Following a successful one-year pilot, with emphasize on performance monitoring through the use of tracers and mapping of high permeability streaks, the WAG process has been gradually expanded to include six injectors.
To avoid sulphate scale, injection of seawater has been replaced by injection of formation water produced from Tertiary sands in the shallow Utsira formation.
P. 103
A Techno-Economic Feasibility Study of Asphaltene Inhibition Squeeze Treatments
Authors: Lullo Alberto G. Di , Lockhart Thomas P. , Carniani Carlo , Tambini Mauro 
Published: December 2007

Abstract
Down-hole asphaltene deposition is an increasingly important issue for many oil fields and has stimulated interest in developing both remedial and prevention technologies. In previous work we have developed asphaltene solvents which optimize remedial treatments for the Villafortuna-Trecate field.
The work described here was aimed at assessing the possibility to achieve further cost reductions through adsorption squeeze treatments with an asphaltene deposition inhibitor. This objective is both economically and technically ambitious since squeeze treatments must compete with optimized solvent washes and because their success is based on the mutual interactions among additive, rock and produced fluids.
We have systematically studied the interplay between the technical and economic aspects of the intended treatment, with the purpose of identifying a priori the conditions giving rise to economically attractive treatments. This has been achieved by comparing the cost per year of the squeeze treatments, computed as a function of the relevant parameters (rock and inhibitor characteristics, well production, desired treatment life and job execution) through the application of a chemical adsorption squeeze simulator, with the annual costs of solvent washes. The acceptable asphaltene inhibitor "profile" thus obtained has turned out to be a powerful guide for laboratory experiments to select candidates for trial treatments.
The main conclusions are different for the case of high pressure reservoirs, for which the damage does not induce any decrease in production flow rate, and low-pressure reservoirs, for which the damage is associated with a production decrease over time.
For high-pressure reservoirs, high-productivity wells (&gt; 300 m3/day) impose severe constraints on inhibitor performance, including activity at concentrations below 10 ppm and stringent adsorption/desorption behavior. For low-productivity wells (&lt; 100 m3/day), instead, inhibitor activity at 50 ppm becomes acceptable, thus enlarging the class of products that are potential candidates for the intended application.
For low-pressure reservoirs, results depend on the fraction of production lost during asphaltene damage and on the capability of the additive to keep production constant during its period of activity. For high-production wells, the range of applicability of squeeze treatments may be significantly enlarged.
Example data are presented for the Eni – Agip Division Villafortuna-Trecate field, but the method employed is general and can be used to evaluate applicability to other fields.
Inflow Performance Relationships of Horizontal and Multibranched Wells in a Solution- Gas-Drive Reservoir
Authors: Retnanto Albertus , Economides Michael J. 
Published: December 2007

Abstract
In predicting and optimizing the performance of single and multiple wells, or complex well architecture, within a drainage or flow unit, we have favored benchmark analytical or semianalytical models. Recently, a general productivity model has been constructed and presented that allows for the performance prediction of any single- and multi-well configuration within any reservoir geometry in both isotropic and anisotropic media. Such an approximation is known to have limitations when applied to two-phase reservoir flow. This work used a numerical simulator to generate IPR's for horizontal or multibranched wells producing from a solution- gas-drive reservoir. First, a base case is considered with typical fluid, rock, and reservoir properties. Then, variations from the base case are investigated. These variations cover a wide range of fluid, reservoir, and well characteristics. The effects of numerous reservoir and fluid properties on the calculated curves are investigated. Bubblepoint pressure and reservoir depletion have a significant effect on the curves. A generalized dimensionless IPR based on nonlinear regression analysis of simulator results is developed. This IPR curve is then used to predict the performance of horiz'ontal and multibranched wells in a solution-gas-drive reservoir combined with our productivity model. For relatively low bubblepoint pressures, the curves coalesce on Vogel's classic relationship. For higher pressures they deviate substantially.
P. 255
Proposal for Certification Program for Petroleum Engineers
Authors: Arnold Charles W. 
Published: December 2007

GOAL
The proposed Certification Program is a technical-professional recognition program to enhance the professional stature and welfare of petroleum engineers. The objectives of the program are:to encourage and reflect the continuing updating of skills by petroleum engineers;to identify and discern the clearly competent professional;to foster continuing recognition of the competent petroleum engineer in his professional career; andto aid the advancement of the technical and scientific disciplines associated with the profession.

CERTIFICATION AND REGISTRATION
The proposed Certification Program compliments and supplements professional registration programs. Registration means legal professional registration programs. Registration means legal license to practice in a particular geographical area; certification means recognition of an individual's continuing technical competence to engage in professional practice.
In areas where no registration laws exist to cover work by petroleum engineers, the Certification Program sponsored by the Society of Petroleum Engineers could provide a form of recognition of competency Petroleum Engineers could provide a form of recognition of competency in petroleum engineering principles and practices.

ELIGIBILITY
To gain certification under the SPE-sponsored program, the applicant must meet the following requirements:Experience: A minimum of six years' experience in an engineering capacity related to the petroleum industry, preferably in the exploration, drilling, production, or pipelining areas. Such experience can include positions in industry, government, or in teaching at a four-year college or university. Credit of one year for a Masters degree and two years for a Doctorate degree will be provided.Registration: A current license as a Registered Professional Engineer in the state in which he practices.Education: (Applies only for those petroleum engineers who, for reason of residency, are unable to qualify for engineering registration at the time of application for certification.) A degree in engineering, engineering science, or applied science from a college or university whose engineering or scientific curricula is approved by the Engineers Council for Professional Development (ECPD) or the SPE Board of Directors.
Maximizing Production From Gravel Packed Wells at Gullfaks Field by Stimulation and Installation of Multiphase Booster Pumps
Authors: Andersen K.I. 
Published: December 2007

Abstract
The Tarbert and Ness formations in Gullfaks are poorly consolidated with high porosity and productivity. Mound 50 cased hole gravel packs have been installed to date, most of which have performed well with regard to sand control.
Data obtained from permanent downhole pressure gauges show a significanfly lower Productivity Index in the gravel packed wells compared to conventionally perforated producers. At increasing drawdown and watercuts, wells with PI less than 100 Sm3/D/bar (40 BBL/psi) become rate limited by the 65 bar (1000 psi) separator pressure at Gullfaks.
Maintaining and improving production from the individual gravel packed wells must therefore be done by stimulation or by artificially reducing backpressure against the wellhead.
Chemical treatments to remove near-wellbore damage have been effective in several cases, yielding a temporary or permanent increase in productivity and oilrate. Calcium carbonate scale can be efficiently removed by bullheading 5 % HCl. Wells which do not respond to acid or have risk of increased watercut can be mechanically stimulated by reperforating the gravel pack. This will generally induce a sand limitation.
In 1994, a pilot multiphase pump unit was installed at the Gullfaks A platform to gain operating experience with the technology and improve production from two of the gravelpacked wells. The pump has proved capable of increasing production from the A-28 well by 300 Sm3/D (1800 BOPD) and has extended the lifetime of the 1000 Sm3/D A-5H well by one year.
Based on the positive results of the pilot programme, 3 new multiphase pump units of higher capacity will be installed topside Gullfaks A and Gullfaks B during 1998/99. This system will be capable of boosting a total of nine wells from 45 bar manifold pressure up to the required 65 bar separator inlet pressure.
P. 439