bluuebunny/crossref_metadata_2025 huggingface dataset:
Utilizing Acoustic Standoff Measurements to Improve the Accuracy of Density and Neutron Measurements
Authors: Minette Daniel C. , Molz Eric
Published: December 2007

An improved method of determining and reducing the impact of borehole size and standoff on the measurement of formation density and neutron porosity has been developed. The use of standoff based binning in the density tool provides the first simultaneous measurement of density and compensation at several different standoffs.

In addition to providing standoff binning for the density, the three axis caliper provides a robust measure of the borehole size. This borehole size is used to calculate both the borehole size correction and standoff correction for the neutron tool. Techniques for accurately making these corrections while rotating and while sliding will be given.

The advantages of this technique are observed in both laboratory and downhole formations. The laboratory work will include the techniques used to make the standoff measurement. They will also include comparisons of measurements made with and without standoff based binning. Once the response in the lab is established, field test logs will be considered. Densities obtained at different standoffs as well as the optimized density will be presented to provide a quantitative measure of the effects of standoff, as well as to demonstrate the accuracy of the optimized density measurement. The comparison of MWD neutron logs with wireline neutron logs provides a measure of the accuracy of corrections while sliding and while rotating. In this manner we will see several independent measures of the improvement in the accuracy of the density and neutron measurements afforded by the use of standoff based binning and the three axis acoustic caliper.
Measuring Strategic Investment Value
Authors: Campbell J. M. , Campbell Robert A. , Brown Stewart
Published: December 2007

The quest for better investment decisions, especially under conditions of low prices, has stimulated interest in new methods for quantifying and managing projects. Journals are full of articles outlining the benefits of options theory, decision-trees, contingent claims analysis, simulations, portfolio theory, etc. Each method corrects a specified, well-documented deficiency in traditional valuation procedures.

This paper summarizes the recent criticisms of traditional methods, especially the gap between individual project valuation methods and the strategic objectives of the organization. After reviewing the limitations of traditional discounted cash flow (DCF) analysis, including NPV, IRR, etc., we seek to outline a more comprehensive understanding of DCF that corrects the inherent contradictions at work in most organizations, especially with the tendency to emphasize short-run objectives at the expense of longer-term, strategic investments.
The Fallacy of the Hockey Stick Projection
Authors: McMichael Claude
Published: December 2007

Uncertainty assessment is gaining industry acceptance as an essential part of reservoir and project evaluations. Major research efforts have been undertaken and significant progress made in techniques to evaluate risks. These new techniques provide better estimates of reservoir volumes and future production performance, as well as, defining the uncertainty associated with these estimates. Unfortunately, most research efforts have focused on technical risks and few have studied the equally important risk due to economic and price uncertainty.

Traditionally within the industry, price uncertainty is assessed using a range of forecasts representing the optimistic, most likely, and pessimistic cases. These forecasts are commonly represented by monotonically increasing future prices and, due to their characteristic shape, often referred to as "hockey stick" projections. While common, such projections demonstrate little resemblance to historical price performance and have proven to be poor projectors of future prices.

This paper proposes a new approach based on crude price history over a fourteen-year period from 1/1/85 through 1/1/99. The method assumes that the observed price changes represent "normal price fluctuations" and that future price performance will be statistically similar to the historical data. The "bootstrap" method is used in conjunction with historical data to estimate a statistically similar set of future price forecasts. Each of these distinct forecasts has the same statistical properties and variability as the historical data. The set of price forecasts is then used to evaluate the impact of "normal price fluctuations" on project economic uncertainty.

Application of the method is demonstrated with examples. The frequency distributions of key economic indicators are evaluated for the example case. These can be used to establish the economic viability and associates risk of the project.

In practice, the method is easily applied and most useful in defining the sensitivity of a project's economic viability to "normal price fluctuations" irrespective of the underlying causes of the fluctuations.
Study of Sweet Corrosion at Low Water Cut in Multiphase Pipelines
Authors: Kang C. , Jepson W. P. , Gopal M.
Published: December 2007

Large diameter, long distance multiphase flow lines are now the predominant trend in oil and gas production. Economics demand the use of carbon steel as the material of construction. However, carbon steel is prone to corrosion from the flowing mixture of oil/water and gas. The prediction of the onset of corrosion with increasing water cuts is very important in the design and operation of the flow lines. A study of corrosion for high pressure, large diameter pipelines under horizontal and 2 degrees oil/water/gas multiphase flow conditions was carried out. The water cuts studied were 10%, 20% and 30% ASTM saltwater. A light oil with viscosity of 2 cP was used as the oil phase. Carbon dioxide gas was used in the gas phase. Temperature was maintained at 40 °C. The superficial gas velocities ranged from 1 m/s to 9 m/s under pressure of 0.27 MPa, 0.45 MPa and 0.79 MPa. The predominant flow was found to be slug flow and all corrosion experiments were carried out in this regime.

The results show that measurable corrosion still occurs even at these low water cuts. For example, at a carbon dioxide partial pressure of 0.79 MPa for 30% water, the corrosion rate increases from 2.2 mm/year to 3.3 mm/year with an increase in Froude number from 6 to 12.

The corrosion rate increases with an increase in slug frequency at the same Froude number. At a pressure of 0.27 MPa, Froude number of 6 for 30% water cut, the corrosion rate increases from 0.8 mm/year to 1.4 mm/year with increase in slug frequency from 6 slugs/minute to 38 slugs/minute. At a Froude number of 12, the corrosion rate increases from 1.2 mm/year to 2.3 mm/year with increase in slug frequency from in slug frequency from 6 slugs/minute to 43 slugs/minute.

At a pressure of 0.27 MPa, Froude number of 6 for 10% water cut, no corrosion was observed in horizontal pipes.
Case History of Complex Fracture Behavior in the Hanoi Trough, Vietnam
Authors: Cipolla Craig L. , Mayerhofer Michael , Wilson Brian L.
Published: December 2007

This paper presents a detailed case history of complex fracture behavior in exploratory wells in the Hanoi Trough, Vietnam. The target formations are stacked fluvial channel deposits that occur at depths of 10,000 to 12,000 ft. The initial three wells were drilled from the same pad, with bottomhole locations about 3,000 to 5,000 ft apart and a probable fault between the No. 1 and No. 3 well. The gas reservoirs encountered were slightly over-pressured and varied significantly in quality, with permeability ranging from 0.01 mD to 1 mD. The first three wells were fracture stimulated in an attempt to improve deliverability. However, only one of the three treatments was successful due to complex fracture behavior. A comprehensive data set consisting of core analysis, rock mechanical tests, pre-and post-fracture logs, geochemical analyses, pre- and post-fracture well tests, and detailed fracture modeling was compiled to understand fracture performance in this complex environment. Without such a complete data set, identifying the cause of the treatment failures would probably not have been possible.
Perforating for Stimulation: An Engineered Solution
Authors: Lestz R. S. , Clarke J. N. , Plattner D. , Byrd A. C.
Published: December 2007

Point source perforating has reduced fracture stimulation expenses in the South Texas Lobo trend. Although the producing intervals frequently exceed 100 ft, the operator typically perforates the bottom 5 ft of the interval. Data collected during perforating is used to design optimized fracture-stimulation treatments. The optimized treatments average 55% less proppant than the previously designed jobs using conventional practices with perforations across the entire pay interval. The new well's initial production and sustained performance has been higher than the conventionally stimulated wells of similar potential. In addition, the point source perforated wells have produced significantly less proppant than similar wells with perforations across the entire pay interval. Point source perforating has reduced the cost of perforating, proppant, fluids, equipment rentals, and cleanup.

This case-history paper presents: historical account of previous completion practices (limited entry, multiple-stage fracturing, full-zone perforating)discussion of the "perforating for stimulation" fracturing technique currently usedcomparison of production resultsformation evaluation methods (logs, bottomhole gauges)perforating methods (phasing, charges, perforating interval selection)
Orienting Live Well Perforating Technique Provides Innovative Sand Control Method in the North Sea
Authors: Eriksen Jan Hilding , Sanfilippo Francesco , Kvamsdal Arne L. , George Flint , Kleppa Erling
Published: December 2007

The Varg field is a development in the North Sea operated by Saga Petroleum. It consists of a not-normally-manned wellhead platform (WHP) with dry wellheads and a floating production storage offloading (FPSO) vessel for processing the crude. The reservoir is heterogeneous sandstone of Upper Jurassic age, with estimated reserves of approximately 35 million stock-tank barrels.

During development planning of the field, it was felt that sand production was likely to occur, and this phenomenon was actually experienced during well testing. Since this development was considered to be a marginal field, an extensive program was initiated to review and select a technical completion solution that would minimize the risk of sand production so that production potentials could be maximized. This paper will discuss how a unique perforating solution was developed to provide the controls needed to manage the potential for sand production.

The first part of this paper will summarize: 1) the drainage strategy and implications of this strategy on selecting the perforation intervals, and 2) results of a rock mechanics study that focused on the conditions critical for the onset of sand production as well as recommendations for minimizing the risk. The primary recommendations were to avoid perforation of the weakest intervals and to shoot perforations that would be oriented parallel to the maximum horizontal stress.

The second part of the paper will describe how successful oriented perforating was achieved in these wells. The primary completion challenges included the following: Development of a slickline system that could perforate the entire zone simultaneously in a given direction in a vertical well.A means to remove the perforating guns from the well without having to kill it after completion of the perforation as there was insufficient rathole to leave the guns in the hole.

An oriented modular perforating system was developed so that the above conditions could be achieved. The requirements were met by installing a gun anchor in the well before the completion was installed. Then, the orientation of an orienting lug was measured with a gyro, and based on the data from the survey, the guns were aligned in the correct orientation. Subsequently, gun sections of length maximized to available lubricator length were run on slickline. The gun section aligned itself automatically to the measured orientation of the orienting lug because of the equipment design. Currently, three wells have been perforated using this system, and the desired results have been obtained.
Simulation of the Immiscible WAG Process Using Cycle-Dependent Three-Phase Relative Permeabilities
Authors: Larsen Johne Alex , Skauge Arne
Published: December 2007

Oil recovery by immiscible WAG is dependent on the saturation cycles that occur in a core-flood or in the reservoir. For the reservoir case, segregation of gas and water can generate other saturation cycles than in a core-flood. In order to predict WAG behavior in the reservoir from experimental results, numerical models with an effective hysteresis description of the three-phase oil, water and gas relative permeabilities should be considered.

There has earlier been developed a methodology that accounts for both three-phase flow effects and hysteresis effects in numerical simulations of the immiscible WAG process. Simulation studies have shown how three-phase flow description may influence the choice of drive mechanisms and also the design of a WAG process.

Furthermore, a principal component analysis (PCA) is conducted on the simulation model that is consistent with the experimental data. The results from the PCA showed how the hysteresis parameters in the simulation model may be correlated to the physical system. The PCA analysis describe how the three-phase effects in water and gas relative permeabilities are connected to oil recovery.

The results show that the cycle-dependent relative permeabilities increase the potential for WAG. Furthermore, the oil production trends with respect to slug length and water-oil ratio is different for models with cycle-dependent hysteresis and without hysteresis.
A New Three-Phase Relative Permeability Model For Various Wettability Conditions
Authors: Moulu J-C. , Vizika O. , Egermann P. , Kalaydjian F.
Published: December 2007

A mathematical model for three-phase flow has been previously developed and validated in water-wet and spreading conditions. The model was based on a description of the porous medium considered as a set of fractal pores. The fluids are allowed to flow together in a same pore, gas in the center, and, for water-wet conditions, water in the vicinity of the walls and oil as an intermediate phase.

The objective of the present study is to confirm that the above model is able, when properly applied, to describe more general wetting conditions. Three-phase relative permeabilities are obtained by history matching gas injection experiments performed in water-wet and oil-wet porous media. Two fluid systems characterized by spreading and non-spreading of oil on water in presence of gas were used. The model is properly modified to take into account different wetting conditions through a wettability index.

It is shown that the model is able to correctly predict oil recovery and breakthrough time for a series of gas injection tests performed under secondary and tertiary conditions. In water-wet condition, the presence of water next to the solid wall determines the shape of the pore space available for the oil and gas flow. It is observed that the fractal linear dimension decreases, with increasing water saturation, from the dimension of the roughness (DL=1.72) to the one of a cylindrical pore (DL≈1). In oil-wet condition, water looses its ability to model the wall of the medium since oil is preferentially in contact with the solid surface. This leads to a constant DL, the value of which corresponds to the surface roughness. In this last case the presence of water in the center of the pores decreases the gas mobility.
Validation of a Modified Carman-Kozeny Equation To Model Two-Phase Relative Permeabilities
Authors: Alpak Faruk O. , Lake Larry W. , Embid Sonia M.
Published: December 2007

This paper presents a validation of an internally consistent, physically based model for relative permeability based on an extension of the Carman-Kozeny (CK) equation. The modified CK (MCK) expression is a function of surface areas of fluid-fluid and fluid-rock interfaces, as well as fluid saturations and tortuosity. The model uses interfacial and surface areas determined from capillary pressure measurements and, by this means, can incorporate variable wettability and hysteresis as well as assuring consistency of petrophysical properties.

To validate the MCK approach, the model is fit to experiments where both capillary pressure and relative permeability are measured simultaneously during flow. The MCK model is further fit to literature-reported water-oil experimental data. Besides the MCK model, each data set is fit with a modification of the commonly used Brooks-Corey (MBC) model to compare the performances of the two.

The surface areas derived from capillary pressure relationship used in the MCK model provide a good description of the experimental relative permeabilities measured under the same conditions. The investigated MCK model fits experimental data almost as well as the MBC model. Furthermore, the MCK model is physically based and appears to agree with the wetting characteristics of the investigated porous media when these are known.
Wave Structure in WAG Recovery
Authors: Marchesin Dan , Plohr Bradley J.
Published: December 2007

For immiscible three-phase flow, potentially three-quarters of the oil recovered through a WAG process can be caused by a non-Buckley-Leverett "transitional" shock wave. This non-classical kind of wave is common in three-phase flow. In this paper, we show how transitional waves arise in WAG flow and how they can be calculated by semi-analytic methods, which are helpful in the design of effective WAG recovery strategies.
Influence of Connate Water and Condensate Saturation on Inertial Effects in Gas-Condensate Fields
Authors: Lombard J-M. , Longeron D. , Kalaydjian F.
Published: December 2007

Reliable predictions of productivity decline of gas-condensate wells require a proper description of complex flow behavior occurring in the near wellbore region. In that region, high pressure gradient induces both large condensate saturation and high gas velocities which may lead to significant deviations from Darcy's law for gas permeability. At the present time, no physically relevant model does exist which takes into account these non-Darcian two phase flow phenomena. This paper presents a contribution to the improvement of the description of gas-condensate flowing properties in the near-wellbore region. A laboratory study has been performed with the aims (i) to estimate the influence of the pore structure on the gas inertial coefficient β and (ii) to integrate the effect of the condensate dropout in the Forchheimer flow equation. Specific laboratory equipment has been built in order to perform gas-condensate displacements under conditions as representative as possible of near wellbore conditions i.e. pressure, temperature and velocities up to 1.5cm/s. Experiments were conducted to measure β on sandpacks and sandstone core samples, with and without connate water saturation (Swi), using dry gas (N2) and analog gas-condensate systems (C1-C3 mixtures). For dry gas floods, the measured β-values were found in good agreement with previous published data. β was found to increase with water (immobile) saturation. In addition a new correlation between β and a mean pore radius, r*, is proposed. Gas-condensate steady state experiments performed at different values of condensate saturation showed that β-values increased with the total liquid saturation. Finally a comprehensive methodology is presented to determine, for each specific application, the relevant parameters which must be taken into account to correctly predict the productivity decline.
Multiphase Non-Darcy Flow in Gas-Condensate Reservoirs
Authors: Wang X. , Mohanty K. K.
Published: December 2007

The understanding of multiphase non-Darcy flow is important to the modeling of production from gas-condensate reservoirs. A pore-scale network model is presented here for gas-condensate flow. Porous media are modeled by networks of pore bodies interconnected by pore throats. Pore bodies and throats are characterized by their connectivity, shape, and radii distributions. Pore-level laws are identified from previously published micromodel and multiphase pipe flow experiments. The condensate can flow due to three mechanisms: pressure gradient within the sample-spanning condensate phase, movement of condensate slugs, and condensate droplets carried by the gas flow. The second mechanism appears at high capillary numbers and the third mechanism at high Reynolds numbers. Inertial terms are important for high rate gas flows. This model has been used to identify several flow regimes important to gas-condensate flow. The effect of pore structure is calculated on gas and condensate relative permeabilities in the low capillary number regime. The relative permeabilities and non-Darcy coefficients have been computed for the low condensate saturation-high pressure gradient flow regime.
Isolation and Characterization of Thermophilic Microorganisms from Malaysian Oil Fields
Authors: Illias R. M. , Ooi S. W. , Idris A. K.
Published: December 2007

Oil and water samples were colected from selected Malaysian oil wells and all the experimental works were carried out in laboratory. The samples have been grown in enrichment medium containing hydrocarbon and incubated at temperatures from 40°C to 60°C. Sixteen thermophilic microorganisms have been isolated. All the isolates are able to grow at aerobic and anaerobic condition. Preliminary characterization indicated about 4 groups of gram-positive rod-shaped microorganisms. Growth temperature studies have been done for these isolates, and found that most of the isolates grown better at temperature ranged from 45°C to 50°C. The purpose of this study is to demonstrate the presence of large number of thermophilic microorganisms in Malaysian oil reservoir. This is still a new information for Malaysian oil industry. The isolated microorganisms are capable of producing biopolymer, biosurfactant, and acids, which have vast application in Microbial Enhanced Oil Recovery (MEOR) and environmental biotechnology.
Pore-Size Distributions in Vuggy Carbonates From Core Images, NMR, and Capillary Pressure
Authors: Ausbrooks Robin , Hurley Neil F. , May Andrew , Neese Douglas G.
Published: December 2007

Vugs, which are defined as pores larger than adjacent grains, are common in many carbonate reservoirs. Such pores are not always recognized by conventional wireline logs. The purpose of this study is to compare pore-size distributions in Oligocene carbonates from China using core, borehole images, nuclear magnetic resonance, and capillary pressure.

The Kerr-McGee CFD2-1-2 well was drilled in the Bohai Basin in China. The reservoir consists of dolomitic limestones and fractured dolomite. The core (25 meters) was polished and inked with fluorescent paint, then photographed under black light to generate high-resolution, 2-D black and white photos. Image analysis produced detailed information about vug size and depth. Core images were then used to calibrate a Formation MicroImager (FMI) log, so that pixel counts of vugs from the FMI would match core observations.

Nuclear magnetic resonance (NMR) logs measure the T2 relaxation time, a parameter that is a function of pore size and reservoir fluid composition. Laboratory NMR measurements for six core plugs have been compared to pore-size distributions from core images. These distributions are comparable for high T2s (above 92 milliseconds).

Mercury intrusion capillary pressure (MICP) measurements are used to determine pore-throat size distributions. These distributions, which can be directly compared to NMR and image analysis pore-size distributions, have very similar shapes.

The net result of this study is that a technique has been developed to relate core-calibrated borehole images to NMR and MICP data. This is an important step in the difficult process of understanding NMR log behavior in vuggy carbonate rocks.
Methodology Implemented in Assessing and Monitoring Hole Stability Concerns in Openhole Horizontal Wellbores in Carbonate Reservoirs
Authors: Salamy S. P. , Faddagh H. A. , Ajmi A. M. , Lauten W. T. , Mubarak H. K.
Published: December 2007

Hole stability concerns are generally relevant to sandstone reservoirs, especially those characterized as being incompetent in terms of their rock mechanical properties. In general, carbonate rocks of the Middle East are competent with the vast majority of the wells completed openhole.

Recent field development of a carbonate reservoir in the Middle East highlighted the weak nature of the reservoir rock in terms of its mechanical properties. A rock mechanics-testing program initiated on core samples revealed that the reservoir rock is relatively weak with the majority of the rocks tested having unconfined compressive strengths less than 2,000 psi. Hole stability concerns surfaced in two of the initial development vertical wells reflected by a stuck logging tool in one and a tight hole in the other.

A comprehensive production-testing program was conducted to assess the extent of hole instability during shut-in and flowing periods, and to calibrate the rock mechanical properties. Four horizontal test wells were selected, and each tested by first running 4-arm caliper logs, followed by a 14-day flow period at maximum possible rates, and finally running production and caliper logs at the end of the test. Caliper logs from these tests established the baseline data for hole size changes and provided insights on the effect of production on wellbore stability.

A monitoring program was initiated to monitor the hole stability before and after field start-up. Prior to field startup and during the shut-in phase, two caliper campaigns were conducted on the test wells. In addition, state-of-the-art sonic logs were implemented in several vertical and horizontal wells to evaluate the field stresses and provide insights on wellbore stability. Results of the shut-in monitoring campaign indicated that there was no immediate hole collapse. However, it was observed that hole size changed with time, with more significant changes occurring in wells characterized as having weak facies.

Post-field start-up monitoring campaign was executed six months after field start-up. Meanwhile, experiments will be conducted in the lab to assess hole stability by predicting pore collapse through acoustic velocity measurements.
Defining Fluid Distribution and Fluid Contacts for Dynamically Charged Reservoirs
Authors: Siddiqui Fareed Iqbal
Published: December 2007

Defining fluid contacts(GWC/OWC/GOC) is one of the major variables for defining the initial hydrocarbons in place. In exploratory wells RFT/MDT is often used to define OWC/GWC. In defining contacts static capillary-buoyancy equilibrium is assumed. There is ample field evidence that many of the existing reservoirs are actively being charged from the source rocks. Under these conditions the assumption of static fluid distributions may not be valid and dynamic conditions should be used for defining the fluid distributions and the contacts.

This paper defines the fluid distributions and fluid contacts for dynamically charged reservoirs. The method is based on the recently proposed Dynamic Theory of Hydrocarbon Migration and Trapping. The results of numerous numerical simulations show that assuming static saturation profiles may not be valid for reservoirs having active influx of fluids into them. This is true even at very small influx rates (10−9 m/s-10−14 m/s). The pressure profiles for the static case (no viscous forces) are compared and contrasted with the dynamic pressure profiles. The dynamic pressure drops can be explained on the basis of Darcy's law and relative permeability effects under extreme saturations. These pressure drops are then used to calculate the saturation distribution in the hydrocarbon column and the transition zones. The results show that if the assumption of static equilibrium is used for the dynamically charged reservoirs it will lead to the underestimation of the initial hydrocarbon in place. The non-equilibrium effects can also explain free water production from zones far above the transition zone, expected, on the basis of static assumption. The interpretation of MDT data under both static and dynamic conditions is also discussed.
Predicting 4D Seismic Performance Using an Integrated Flow Model
Authors: Fanchi John R.
Published: December 2007

Changes in reservoir geophysical attributes during the life of a reservoir can be predicted by calculating the attributes as a function of time. This paper describes the calculation of reservoir geophysical attributes using an integrated flow model for the following reservoir management scenarios: water injection into an undersaturated oil reservoir; gas injection into an undersaturated, light oil reservoir; gas cycling in a retrograde condensate reservoir; solvent injection into a volatile oil reservoir; and aquifer influx into a gas reservoir.
Efficient Conditioning of 3D Fine-Scale Reservoir Model To Multiphase Production Data Using Streamline-Based Coarse-Scale Inversion and Geostatistical Downscaling
Authors: Tran Thomas T. , Wen Xian-Huan , Behrens Ronald A.
Published: December 2007

In addition to seismic and well constraints, production data must be integrated into geostatistical reservoir models for reliable reservoir performance predictions. An iterative inversion algorithm is required for such integration and is usually computationally intensive since forward flow simulation must be performed at each iteration. This paper presents an efficient approach for generating fine-scale three dimensional (3D) reservoir models that are conditioned to multiphase production data by combining a recently developed streamline-based inversion technique with a geostatistical downscaling algorithm.

Production data can not reveal fine scale details of reservoir heterogeneity. By solving the streamline pressure solution at a coarse scale consistent with the production data we are able to invert numerous geostatistical realizations. Additionally, the streamline method allows fine resolution along the 1D streamlines independent of the coarse grid pressure solution so we do not need to explicitly address multiphase scale-up.

Multiple geostatistical fine scale models are up-scaled to a coarse scale used in the inversion process. After inversion, the models are each geostatistically downscaled to multiple fine scale realizations. These fine scale models are now preconditioned to the production data and can be up-scaled to any scale for final flow simulation.

A 3D extension of the prior 2D sequential-self calibration method (SSC) is developed for the inversion step. This method updates the coarse models to match production data while preserving as much of geostatistical constraint as possible. A new geostatistical algorithm is developed for the downscaling step. We use Sequential Gaussian Simulation with either block kriging or Bayesian updating to "downscale" the history-matched coarse scale models to fine-scale models honoring fine-scale spatial statistics. Combining these two developments we are able to efficiently generate multiple fine scale geostatistical models constrained to well and production data.
Characterisation of Composition and PVT Properties of Petroleum Inclusions: Implications of Reservoir Filling and Compartmentalisation
Authors: Munz I. A. , Johansen H. , Johansen I.
Published: December 2007

In this paper we present an approach to PVT (=pressure-volume-temperature) modelling of petroleum inclusions. A compositional range from C1 to C30 is obtained from gas chromatographic analysis. The fluid composition has been characterised by quantification of individual components in the light hydrocarbon range (C6-C5) and pseudocomponents in the C6-C30 range. Average values for the properties of pseudocomponents have been found from a literature survey. Estimation of the residue (C30+) was based on extrapolation of the distribution of pseudocomponents in the C30- range. The compositional characterisation in combination with microthermometry analyses result in estimation of phase-envelopes and fluid densities by using an equation of state. Temperature control is established from analyses of coeval aqueous inclusions. The pressure is estimated by isochore calculations for the petroleum inclusions. Application of the method for reservoir characterisation is addressed.
A Unified Mechanistic Model for Steady-State Two-Phase Flow in Wellbores and Pipelines
Authors: Gomez L. E. , Shoham O. , Schmidt Z. , Chokshi R. N. , Brown A. , Northug T.
Published: December 2007

A unified mechanistic model for the prediction of flow pattern, liquid holdup and pressure drop in wellbores and pipelines is presented. The model is based on two-phase flow physical phenomena, incorporating recent developments in this area. It consists of a unified flow pattern prediction model and unified individual models for stratified, slug, bubble, annular and dispersed bubble flow, applicable to the entire range of inclination angles, from horizontal (0°) to upward vertical flow (90°). The model can be applied to vertical wellbores, directional wells, horizontal wells, and pipelines, under normal production operation or artificial lift. The proposed model implements new criteria for eliminating discontinuity problems, providing smooth transitions between the different flow patterns.

The new model has been initially validated against existing, various, elaborated, laboratory and field databases. Following the validation, the model is tested against a new set of field data, from the North Sea and Prudhoe Bay, Alaska, which includes 86 cases. The proposed model is also compared with other 6 most commonly used models and correlations. The model showed an outstanding performance for pressure drop prediction, with −1.3% average error, 5.5% absolute average error and 6.2 standard deviation. The proposed model provides the state-of-the-art of two-phase flow mechanistic modeling and design for the industry.
Spatial Distribution of Oil and Water in Horizontal Pipe Flow
Authors: Soleimani A. , Lawrence C. J. , Hewitt G. F
Published: December 2007

This paper reports a series of experiments to quantify the spatial distribution and identify the flow pattern of liquid-liquid flow in a horizontal 25.4mm (nominal one-inch) tube. Experimental results are presented for Kerosene (EXXOL D80) and tap water at room temperature. Two different measurement techniques (a high frequency impedance probe and a gamma densitometer system) were applied for measuring the volume fraction distribution across the tube and to obtain tomographic results for phase distribution. The use of the gamma densitometer system to obtain the tomographic results in liquid-liquid co-current flow is believed to be the first in this field. These methods are more precise than other techniques such as visualization and help to distinguish certain differences in flow patterns for different superficial velocities and liquid fractions. The two sets of measurements were compared and it was concluded that the gamma densitometer system was a more reliable method to measure the volume fraction. Two important phenomena in liquid-liquid flow were observed:

a) Oil encapsulation by water at low mixture velocity. b) Droplets concentrated at the center of the pipe in the dispersed flow regime. Some possible explanations are given regarding these phenomena.
An Experience in Acidizing Sandstone Reservoirs: A Scientific Approach
Authors: Hashem M. K. , Nasr-El-Din H. A. , Hopkins J. A.
Published: December 2007

Several sandstone fields were recently developed in Saudi Arabia. Various treatments were performed on damaged water injection wells in these fields, however, the performance of treated wells declined over a period of a few months such that these wells required re-acidizing treatments.

A thorough investigation was undertaken to identify the damaging mechanism, recommend suitable acid formulae, assess the effectiveness of the treatment in the field and identify methods to minimize well damage.

Laboratory and field investigations were conducted simultaneously to address formation damage and associated problems. These investigations included determining rock mineralogy, coreflood tests to screen various acid formulae, and collecting field samples to identify the damaging mechanism.

Based on the results of these studies, two acid formulae were selected and applied in the field. More than forty damaged wells were treated with these acid formulae. Because of the low reservoir pressure, these treatments were conducted using a coiled tubing unit and the spent acid was lifted using nitrogen gas. Chemical analysis of acid returns (spent acid) was used to determine the type and concentration of acid additives.

As a result of this study the success rate of acidizing jobs in these fields has increased to more than 85%. The target injection rate was met without drilling additional wells. No secondary precipitation was noted after the treatments. In addition, damage prevention procedures, which were implemented in the field, have resulted in a significant reduction in the frequency of performing acid jobs in these fields.

This paper describes laboratory and fieldwork done to enhance the performance of damaged wells. Furthermore, it discusses the application of various damage prevention procedures in the field.
Case Study of a Novel Acid-Diversion Technique in Carbonate Reservoirs
Authors: Chang F. F. , Love T. , Affeld C. J. , Blevins J. B. , Thomas R. L. , Fu D. K.
Published: December 2007

A novel non-particulate, non-foam diverting agent was developed to improve zone coverage during matrix stimulation of carbonate reservoirs. Typically the treating fluid flows into thief zone/s of high water-saturation and/or higher permeability sections. Higher water cut often results due to over-treating the water zones and inadequate treatment of the hydrocarbon bearing zones. Although foam has been used successfully in diverting acid from the aquifer to the damaged oil zones, the limited nitrogen availability in some areas and additional handling requirements call for a simpler process, especially in long intervals where multiple acid/divertor alternating stages are involved. The newly developed one-additive diverting agent system contains only a viscoelastic surfactant (VES) which can easily be mixed in brine to form a highly viscous gel. The gel maintains its viscosity when contacting water thus temporarily plugs the high water-saturation and/or pre-stimulated zones resulting in diversion of acid into the targeted oil zones.
Acid Etching Patterns in Naturally-Fractured Formations
Authors: Dong Chengli , Hill A. D. , Zhu D.
Published: December 2007

When a naturally fractured carbonate formation is treated with acid at pressures below the fracturing pressure, the acidizing process will likely be different from either a true matrix treatment or an acid fracturing treatment. In a matrix treatment of a relatively homogeneous, un-fractured carbonate, the acid initially penetrates into the pore structure and usually creates wormholes. In an acid fracturing treatment, the acid flows through the relatively wide fracture, resulting in more uniform etching of the fracture walls. In naturally fractured formations, acid could either mainly generate wormholes, as in matrix acidizing of carbonates without natural fractures, or etch the fracture surfaces, as in acid fracturing. Determining the etching pattern is essential for modeling acidizing in carbonates with natural fractures.

We studied the influence of natural fractures on the acid etching pattern. We used two closely contacted rock samples to simulate natural fractures. The gap between the samples was in the range of average natural fracture widths indicated in the literature. The samples were then acidized with 13.5% HCl. Numerous experiments were conducted to determine the acid etching pattern. Our experimental results show that the acid etching pattern of naturally fractured formations depends strongly on the width of the natural fracture. For typical natural fracture widths, the pattern tends to be wormholing, rather than etching of the fracture surfaces. In most experiments, one broad channel was created at the area near the inlet of the samples, and as acid flows down the fracture, the channel narrows quickly and finally becomes a deep narrow wormhole. The effect of natural fractures on acid etching pattern vanishes as acid moves away from the inlet. As the width of the natural fracture increases, the channel created near the inlet becomes broader and longer, and as the width of natural fracture decreases, the channel becomes narrower and shorter.
Deepwater Cementing Challenges
Authors: Ravi Krishna , Biezen Ewout N. , Lightford Stephen C. , Hibbert Ashley , Greaves Chris
Published: December 2007

Oil and gas wells are being drilled in increasingly deep waters and demand increasingly efficient execution. The water temperature gradient from surface to seabed is non-linear and the properties of shallow formations vary from location to location. These factors add further challenges to the already difficult issues in deepwater drilling. They impact the design of cementing operations more than is generally recognized. In particular, the intrinsic properties of cement slurry such as heat of hydration is generally ignored and standard testing methods are inadequate.

The purpose of this study was to investigate and optimize cementing operations; particularly those related to shallow surface casings in deepwater wells. The following issues will be addressed:

the temperature of the slurry during placement the temperature of the slurry during wait-on-cement (WOC) the gel strength development of the slurry to prevent fluid influx the compressive strength development of slurry to determine earliest safe time to release the conductor (or determine the support of other shallow casing strings)

Both numerical and experimental simulations were used. Temperatures were numerically simulated and were then validated using both laboratory and field data.

Intrinsic properties of the slurry such as heat of hydration and heat capacity were used together with appropriate boundary conditions in a numerical simulation of the temperature during slurry placement and WOC.

A large-scale experimental setup was built in the laboratory to simulate:

The thick cement sheath in deepwater shallow casing annuli. Loose sand/silt surrounding the cement sheath and its dimension relative to the cement sheath. Seabed temperature, e.g. −2 °C at a depth of 800 meters

in the North Sea. The slurry temperature was monitored during curing in the large-scale test setup. There was good agreement between the slurry temperature measured in the large-scale test setup and the numerical study. The simulated temperature is referred to as Simulated Slurry Temperature, or SST. SST is specific to the slurry design and the well parameters.

Slurry was cured in a UCA using both SST and the "conventional" seabed temperature. Based on this work, recommendations for releasing the conductor were made for an offshore job in Norway in 800 metres of water. The cement job was successfully completed based on these recommendations with a significant saving in rig time.

Laboratory tests, numerical simulation and results from a field job are discussed in this paper.
A Laboratory Study on Oilwell Cement and Electrical Conductivity
Authors: Backe K. R. , Lyomov S. K. , Lile O. B.
Published: December 2007

Using electrical conductivity as a parameter to characterise the curing of cement slurries show promising results.

The paper describes how to measure conductivity, including practical observations and gained experience. We found that conductivity as a function of time for each slurry exhibits a characteristic curve form which clearly shows the curing behaviour. A relationship between conductivity and compressive strength was obtained and it was confirmed that rapid curing will reduce the risk of gas migration. Some observations on curing vs. additives are presented as well.

Measuring electrical conductivity is easy, and as such, could be used in the laboratory as a supplement to the equipment recommended by API, or in the field as a quality control during cementing operations.
New Insights Into In-Situ Combustion Simulation for Heavy Oil Reservoirs
Authors: Ambastha A. K. , Kumar M.
Published: December 2007

Accuracy of field-scale numerical simulation results for in-situ combustion performance is not well established in the literature. Often, one starts with a reasonable history match of laboratory in-situ combustion data to formulate the process description for field-level simulation of process performance. Laboratory data are matched using one-dimensional process description with grid block sizes of the order of inches. However, field-level simulation requires three-dimensional process description with grid block sizes of the order of tens of feet. Starting from the use of laboratory data to assist in the process description for in-situ combustion, this paper compares laboratory-validated, numerical simulation results with semi-analytical correlation of Gates and Ramey1, which is based on field data.

This paper investigates the discrepancy between numerical simulation results and field-derived correlation. Limitations of the numerical simulation and correlation techniques in predicting field performance have been identified. A detailed study has been carried out to highlight the most critical parameters for describing in-situ combustion process, and the differences between laboratory and field-scale simulations. Impact of grid-block sizes, heavy oil characterization, dimensionality of the problem, heavy oil viscosity, initial reservoir temperature, and complexity of chemical reactions on production performance was investigated. This study has resulted in several observations that assist in understanding the validity of production performance computations for an in-situ combustion process using a numerical simulator and laboratory combustion tube data. The paper provides a better understanding of the impact and relative significance of process variables, which may be used in improved design of a project.