bluuebunny/crossref_metadata_2025_split huggingface dataset:
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.