bluuebunny/crossref_metadata_2025 huggingface dataset:
Hydrogen-Induced Cracking in Surface Production Systems: Mechanism, Inspection, Repair, and Prevention
Authors: Burk J. D.
Published: December 2007

Hydrogen-induced cracking (HIC) is a materials- and corrosion-related problem that occurs in surface production systems. Steels used to construct sour-gas production facilities and flowlines may corrode from wet hydrogen sulfide (H2S) gas in the production stream. The corrosion process generates hydrogen that may damage the steel, resulting in HIC and other forms of damage from hydrogen. HIC control and prevention are an important consideration in operating surface-facility equipment in a safe and efficient manner. By effectively controlling or preventing HIC damage in surface-facility equipment, operating costs are reduced, potential costly downtime from equipment failure is avoided, and a safe work environment is more easily realized.

We developed an overall approach to understand and deal with the HIC problem in sour-surface production facilities. The approach dealt with understanding the mechanism in steel materials used in surface-facility equipment; implementing state-of-the-art inspection techniques; fitness-for-service (FFS) evaluation to assess damage effect on performance; repair procedures on existing equipment; and finally, establishing steel performance and fabrication requirements to eliminate or reduce HIC damage risk for newly fabricated equipment.

This paper presents the results of laboratory examinations of over 40 steels covering both new and existing equipment, leading to the approaches developed for controlling HIC in existing equipment and for controlling or preventing HIC in new construction. We also present the basis for the approaches developed to deal with HIC in surface production facilities.
The Use of Pulsed-Neutron Capture Logs for Reservoir Management in the Midway-Sunset Field
Authors: Guo D. S. , Smith M. E. , Tucker K. E.
Published: December 2007

Systematic time-lapse pulsed-neutron capture (PNC) logging was conducted during a 2-year steam-foam mechanistic field trial in the steamflooded Monarch reservoir, which is composed of interbedded sandstones, conglomerates, siltstones, and diatomaceous mudstones. Observation wells were drilled with one continuously cored through the reservoir interval and two emptied to facilitate better temperature logging. Uncalibrated PNC log responses in the air-filled wells were normalized to water-filled conditions and were used to generate a series of steam/gas saturation profiles that indicate clearly the dynamics of the fluid and foam in the reservoir during the experiment.

Correlations between neutron capture cross sections (sigma), mineralogy, and rock chemistry from core samples were examined for additional use of the PNC logs for steamflood reservoir characterization. Sigma was found to increase with increasing clay/mica content and diatomite content. This finding may result in improved stratigraphic correlations of the more laterally continuous diatomaceous mudstones based on PNC logs.

The PNC log data from the field trial, when used in conjunction with core, temperature, and pressure data, were critical in developing a better understanding of foam generation and propagation in the reservoir. Furthermore, they minimized the time and cost required to complete the field trial successfully. They also led to opportunities for vertical expansion of steamflooding in the area.
Developing Data Sets for 3D Fracture Propagation Models
Authors: Holditch S. A. , Rahim Zillur
Published: December 2007

This paper shows that by developing correlations, one can generate realistic 3D data sets that will result in more realistic fracture treatment designs.
Evaluation of Fracture Treatments Using a Layered-Reservoir Description: Field Examples
Authors: Rahim Zillur , Holditch S. A. , Zuber M. D. , Buehring D. R.
Published: December 2007

This paper presents a practical analysis technique to determine actual fracture geometry and proppant profile using a three-dimensional (3D) hydraulic-fracturing simulator. The hydraulic-fracturing model used in this study considers the variation of in-situ stress, Young's modulus, Poisson's ratio, and net pay thickness in the productive interval.1–4 When our method is applied, the results from the fracture propagation model conform well with the results we obtain from pressure-buildup and production-data analyses.

This study analyzed hydraulic-fracturing treatments from several wells in the Vicksburg formation of the McAllen Ranch area in south Texas.5,6 We have provided guidelines to properly describe the treatment interval, how to use this information in the analysis of such fracture treatments, and how to confirm the results using pressure-transient tests and production-data analyses. This paper presents examples illustrating that a detailed description of the reservoir layers is essential to properly evaluate hydraulic-fracture treatments.

For the example wells presented in this paper, post-fracture-production and pressure-transient data were available. We have analyzed production and pressure-transient data to estimate permeability and fracture half-length. The values of fracture half-length used to analyze the production data matched closely with those predicted by the fracture model.
Problem Detection During Tripping Operations in Horizontal and Directional Wells
Authors: Cordoso J. Venâncio , Maidla Eric E. , Idagawa L. S.
Published: December 2007

Most directional well drilling problems detected in Brazil, and also verbally reported by service companies abroad, occur during tripping operations. A comprehensive research program was undertaken to study this problem. The work is summarized in this paper, and shows the development of a field analysis procedure that proved to be reliable and thus translates into significant cost savings.

The field data was obtained using an in-house mud logging offshore unit and service companies' drilling sensors. The analysis was performed using the new developed method—Two Stage Type Curve Matching: an alert hook load expert system, followed by a pseudo friction factor "signature" analysis.

Field results showed this to be useful for early borehole detection.
An Assessment of the Mechanical Stability of Wells Offshore Nigeria
Authors: Lowrey John P. , Ottesen Steinar
Published: December 2007

In 1991 lost time due to stuck pipe related drilling problems accounted for approximately 18% of total drilling time in Mobil Producing Nigeria Ultd.'s (MPN) offshore operations. The primary cause of stuck pipe was identified as mechanical wellbore instability. This paper presents an assessment of the mechanical stability of MPN's wells offshore Nigeria. The objectives of the study were to: 1) determine the magnitude of the in-situ principal stresses and material properties of the troublesome Intra-Biafra and Qua Iboe shale sequences; 2) quantify the drilling fluid densities required to drill mechanically stable wells through these formations; 3) review and recommend well planning and operational parameters which aid in minimizing wellbore stability-related drilling problems. The wellbore stability assessment was carried out with the aid of a 3-dimensional wellbore stability model using field derived data from the study area to corroborate the results. The collection and analysis of drilling data (borehole geometry and density logs, pore pressure, leak-off tests, local geology and other relevant well records) to determine the magnitude of the in-situ principal stresses, together with compressive strength tests on formation cores are discussed. Minimum safe drilling fluid densities to promote wellbore stability as a function of well geometry and depth are presented for the most troublesome shales drilled in the study area. Implementation of the results reduced wellbore stability related problems and associated trouble time to less than 5% in 1992.
Average Reservoir Pressure Estimates in a Commingled Reservoir
Authors: Chen H. Y. , Raghavan R. , Poston S. W.
Published: December 2007

Late-transient buildup responses at a well that produces a two-layer reservoir with no-crossflow are studied. The well is located at the center of a circle and the outer boundaries are assumed to be impermeable. The initial pressure is identical in each layer. Our emphasis is on the determination of average reservoir pressure. This study provides (i) a complete description of the buildup trace following the initial-transient period (or the semilog straight line should it exist) by obtaining analytical expressions that highlight the influence of the variables that affect the trace, (ii) a physical interpretation for the value of pressure that corresponds to the level portion of the buildup curve, (iii) an interpretation of average pressure estimate obtained by using the Matthews-Brons-Hazebroek functions for single-layer systems (in this regard a number of insights are provided), (iv) a theoretical justification for the application of the Muskat and the Arps-Smith methods to estimate average reservoir pressure, and (v) a direct method to compute average reservoir pressure. Results are extended to multilayer systems.
The Effect of Crude-Oil Aging Time and Temperature on the Rate of Water Imbibition and Long-Term Recovery by Imbibition
Authors: Zhou Xian-min , Torsæter Ole , Xie Xina , Morrow N. R.
Published: December 2007

We investigated short-term rates of imbibition of water and long-term recovery by spontaneous imbibition for crude oil/brine/rock systems. Increasing the aging time and aging temperature decreased the early time rate of imbibition of water. Moderately water-wet plugs gave the highest recovery by long-term imbibition. We present photographic records of oil production at core surfaces, which are indicative of connectivity and capillary-pressure driving forces for imbibition.
Use of Flow Units as a Tool for Reservoir Description: A Case Study
Authors: Ti Guangming , Ogbe D. O. , Munly Walt , Hatzignatiou D. G.
Published: December 2007

This paper presents a method where fluid flow units are used in reservoir description. We developed the proposed method using core and well-log data from the Endicott field on the North Slope of Alaska. Sedimentary intervals of the cored wells are divided into major zones on the basis of core description information. The major zones are further subdivided into subzones to allow less variation in geologic and petrophysical properties within each subzone and more variation between the subzones. On the basis of the transmissibility, storativity, and net- to- gross-thickness data, the subzones are classified into four distinct fluid flow units by use of the statistical method of cluster analysis.

We use a regression relationship established between the core and well-log data in the cored wells to estimate the permeability of the uncored wells, allowing for extension of flow units to these wells. We present stratigraphic cross sections to illustrate areal variations of the petrophysical properties in the Endicott field.
Why Do Gels Reduce Water Permeability More Than Oil Permeability?
Authors: Liang Jenn-Tai , Sun Haiwang , Seright R. S.
Published: December 2007

A capacity to reduce water permeability much more than oil permeability is critical to the success of gel treatments in production wells if zones cannot be isolated during gel placement. Although several researchers have reported polymers and gels that provide this disproportionate permeability reduction, the explanation for the phenomenon was unclear. In this paper, we examine several possible explanations for why some gels reduce water permeability more than oil permeability. Our experimental results indicate the disproportionate permeability reduction is not caused by gravity or lubrication effects. Results also indicate that gel shrinking and swelling are unlikely to be responsible for the phenomenon. Although wettability may play a role in the disproportionate permeability reduction, it does not appear to be the root cause for water permeability being reduced more than oil permeability. Results from an experiment with an oil-based gel suggest that segregation of oil and water pathways through a porous medium (on a microscopic scale) may play the dominant role in the disproportionate permeability reduction. However, additional work will be required to verify this concept.
Estimation of Horizontal Stresses at Depth in Faulted Regions and Their Relationship to Pore Pressure Variations
Authors: Addis M. A. , Last N. C. , Yassir N. A.
Published: December 2007

This paper focuses on the relationships used for estimating the magnitudes of horizontal stresses acting in faulted sedimentary basins. Relationships are derived here based on the assumptions of a faulted but essentially elastic rock and take into account the tectonic stress component associated with active normal and thrust faults, as well as the pore pressure. The equations presented predict that the orientation of the minimum stress can change once a normal or thrust fault has formed. They further predict that an increase in pore pressure gradient will result in a more isotropic stress state. Field data are used to assess the predictions and include stress-depletion measurements from normally faulted basins and stress measurements performed "at depth" in compressive tectonic "thrust" regions.
Pressure-Transient Testing of Gas Reservoirs With Edge-Waterdrive
Authors: Chen Chih-Cheng , Chu Wei-Chun , Sadighi Soleiman
Published: December 2007

A pattern to recognize the presence of water encroachment and a reliable method for estimation of reserves in single-well gas reservoirs with edge-waterdrive have been developed from analysis of simulated pressure data. An alternative to the traditional interpretation of boundary effects has emerged as a result. This paper discusses the development of this new methodology and presents field examples of buildup data to demonstrate the applicability of the signature.
Parametric Study of Gas Entry Into Cemented Wellbores
Authors: Sabins Fred , Wiggins M. L.
Published: December 2007

A cement slurry is placed in a wellbore to harden into an impermeable mass that seals the annulus from fluid flow and protects the casing from corrosion for the life of the well. If fluid flow does occur in the form of gas migration, expensive remedial squeeze-cementing techniques are generally required.

The objective of the work covered in this paper was to study the parameters that affect entry of gas into a cemented annulus. This research incorporated a detailed study of the factors that contribute to gas influx from the time of initial placement of the slurry, through the gelation or transition state of the slurry, to the set condition. On the basis of the understanding of the processes involved in gas entry, a simulator was developed that predicts the amount of gas that enters a cemented wellbore, and identifies the critical parameters that affect the gas entry.

This study concerns itself with a portion of the gas flow problem: the entry of gas into a cemented annulus — and not with the flow of the gas up through the cement and the formation of a gas channel.

This study will provide insight to the following questions.

What cement properties are important to minimize gas entry? What role does fluid loss play in minimizing gas influx? What well parameters affect gas entry?
Application of Short-Radius Horizontal Boreholes in the Naturally Fractured Yates Field
Authors: Gilman J. R. , Bowzer J. L. , Rothkopf B. W.
Published: December 2007

This paper discusses the performance and simulation of short-radius horizontal boreholes being used in the Marathon-operated Yates Field Unit in west Texas to minimize drawdown and therefore to reduce gas and water coning in a thin oil column. Yates is a very prolific field with extensive fracturing and high-quality reservoir rock. Superimposed on a high-density orthogonal fracture network are widely spaced regional joints with a strong directional tendency. Major questions are how these directional joints affect the horizontal-well performance and whether wells should be drilled parallel or perpendicular to the joints. Dual-permeability reservoir simulation studies were performed to study optimum orientation of the borehole with respect to the natural fracture network. Additionally, optimum well-completion elevation was studied. Forty-six vertical wells have been recompleted as short-radius horizontal boreholes since 1986. The large productivity increase of the horizontal boreholes compared with the previous vertical completions indicates that the wells are intersecting the regional joints.
Structural and Hydrocarbon Histories of the Ivishak (Sadlerochit) Reservoir, Prudhoe Bay Field
Authors: Erickson J. W. , Sneider R. M.
Published: December 2007

The Ivishak (sometimes referred to as the Sadlerochit) reservoir is the largest producing horizon in the Prudhoe Bay field. The field, located on the coastline of the Beaufort Sea, has been divided into eight zones with lower sections being deposited in low-energy, marine and delta-front environments and the remaining zones consisting of sandstones and conglomeratic units deposited by braided streams.1 Subsequent burial, structuring, and hydrocarbon emplacement resulted in a maximum accumulation 40 million years ago, with a hydrocarbon-column thickness of 2,080 ft. Continuing burial resulted in flattening and hydrocarbon spillage, resulting in the configuration at field discovery with a hydrocarbon-column thickness of 1,050 ft. Understanding the structural and hydrocarbon histories is key to understanding and calculating the gas-, oil-, and water-saturation distributions at the time of field discovery because some areas of the reservoir appear to have been in capillary equilibrium with the discovery oil/water contact, while structurally high portions of the reservoir appear to be in equilibrium with conditions at the time of maximum hydrocarbon accumulation.
Rock Types, Depositional History, and Diagenetic Effects, Ivishak Reservoir, Prudhoe Bay Field
Authors: Sneider R. M. , Erickson J. W.
Published: December 2007

The present-day pore system of the Ivishak reservoir is the result of depositional and postdepositional processes. The pore system is a dual system characterized by intergranular porosity, enhanced by leaching, and intragranular microporosity. The combined interaction of deposition and diagenesis together with burial history has caused porosity, permeability, net pay, and water saturation to be highly variable areally and vertically.
Use of Neural Networks for Prediction of Vapor/Liquid EquilibriumKValues for Light-Hydrocarbon Mixtures
Authors: Habiballah W. A. , Startzman R. A. , Barrufet M. A.
Published: December 2007

Equilibrium ratios play a fundamental role in the understanding of phase behavior of hydrocarbon mixtures. They are important in predicting compositional changes under varying temperature and pressure in reservoirs, surface separators, and production and transportation facilities. In particular, they are critical for reliable and successful compositional reservoir simulation. This paper presents a new approach for predicting K values with neural networks (NN's). The method is applied to binary and multicomponent mixtures, and K-value prediction accuracy is on the order of the traditional methods. However, computing speed is significantly faster.
A New Simple Method To Estimate Fracture Pressure Gradient
Authors: Rocha L. A. , Bourgoyne A. T.
Published: December 2007

Projecting safer and more economic wells calls for estimating correctly the fracture pressure gradient. On the other hand, a poor prediction of the fracture pressure gradient may lead to serious accidents such as lost circulation followed by a kick. Although these kind of accidents can occur in any phase of the well, drilling shallow formations can offer additional dangerous due to shallow gas kicks, because they have the potential of becoming a shallow gas blowout leading sometimes to the formation of craters.

Often, one of the main problem when estimating the fracture pressure gradient is the lack of data. In fact, drilling engineers generally face situations where only leak off test data (frequently having questionable results) are available. This problem is normally the case when drilling shallow formations where very few information are collected.

This paper presents a new method to estimate fracture pressure gradient. The proposed method has the advantage of (a) using only the knowledge of leak off test data and (b) being independent of the pore pressure. The method is based on a new concept called "pseudo-over- burden pressure", defined as the overburden pressure a formation would exhibit if it were plastic. The method was applied in several areas of the world such as U.S. Gulf Coast (Mississippi Canyon and Green Canyon) with very good results.
Estimation of Recovery Factor in Light-Oil Air-Injection Projects
Authors: Fassihi M. R. , Yannimaras D. V. , Kumar V. K.
Published: December 2007

In deep, high-pressure light-oil reservoirs, air injection provides several advantages compared with other improved recovery injection processes. The combination of rapid pressurization, spontaneous ignition, complete oxygen utilization, stripping of the light hydrocarbons [natural gas liquids (NGL's)], and near miscibility of the in-situ-generated combustion gases with the reservoir oil results in improved recovery. The availability of the injectant should allow wide application of air injection. Estimation of the recovery factor for this process is subject to uncertainties and requires history matching. To date, computer models have shown limited predictive capability owing to the complexity of the process. Also, an estimate of the fuel laydown at high pressure is not available.

In this paper, a method is proposed for estimating the recovery factor on the basis of the producing gas/oil ratio (GOR) of the field. The field results of two ongoing air-injection projects, Medicine Pole Hills Unit (MPHU) in North Dakota and Buffalo Red River Unit (BRRU) in South Dakota, are used to illustrate this technique. MPHU and BRRU are unique applications because they use high-pressure air injection into deep, high-temperature, low-permeability carbonate reservoirs producing light oils. The produced-gas analysis from MPHU is used to arrive at the fuel laydown and the H/C ratio of the fuel. This is the first time the fuel laydown has been estimated for a high-pressure air-injection project in a light-oil reservoir. Finally, the results of the produced-gas analysis are used to arrive at the NGL content of the effluent stream. The combined oil recovery and NGL production provide the basis for estimating the total recovery factor for this field. Such an estimate can be used by other operators to assess the economic viability of this process in their fields.
Assessment of Analysis of an Instrumented Drilling Jackup Conductor
Authors: Hamel Djamel , Robinson Richard , Stonor R. W. P.
Published: December 2007

This paper presents an assessment of some of the results of an internationally funded joint-industry project to measure the dynamic behavior of a drilling conductor run from a large jackup platform operating in deep water at the North Sea. Three different elevations spanning the conductor were instrumented with environmentally protected strain gauges while the rig was operating. The objective was to gather data for selected storms for subsequent spectral and statistical analyses and to validate finite-element analysis (FEA) of a drilling-conductor system. The response amplitude operators (RAO's) from the analysis showed good agreement with measured RAO's. This agreement increases confidence in the validity of the loading and response calculation methods currently available for the design of drilling conductors. In the frequency analysis, the computed natural periods showed good agreement with those measured under different drilling conditions. Measurements showed that the natural frequency oscillation of the conductor was mainly in the first mode of vibration. In the time-domain analysis, the computed bending loads were found in good agreement with measured values, particularly at the middle and lower gauged levels. The analytical results showed that, for small waves, the dynamic amplification was substantial when comparing static and dynamic analytical techniques. However, for large design waves, the dynamic amplification was found to be small and the static analytical technique was found to be accurate in predicting environmentally induced loads.
Simultaneous Use of Ester and CO2 Sinale-Well Tracers
Authors: Wellington S. L. , Richardson E. A.
Published: December 2007

This paper documents the consecutive and concurrent use of both ester and CO2 tracer chemistries in the same single-well test application. The simplicity of the CO2 system, which uses water-soluble-only injectants, and a no-soak/soak test sequence allowed determination of definitive residual oil saturation (ROS) values.
Operator/Contractor Teamwork is the Key to Performance Improvement
Authors: Robins K. B. , Roberts J. D. M.
Published: December 2007

The contract strategies developed by the two major E&P companies operating in the North Sea emphasise teamwork between operator and contractors to achieve the common goal of maximising project value. These strategies have had significant repercussions across the whole industry.

This paper compares these strategies, concluding that although they are structurally different, they have the same fundamental objective. It describes the evolution of what these operators consider to be their "core business", with the resultant changing roles for both operator and contractor staff.

Several examples of results achieved through implementing these changes are described, highlighting the need for a structured performance measurement system to quantify the success of these initiatives. Finally the potential for even greater efficiency improvements through further industry wide cooperation is emphasised.
An Evolving Approach in the Analysis of Stress-Test Pressure-Decline Data
Authors: Middlebrook M. L. , Aud W. W. , Harkrider J. D. , Hansen J. T.
Published: December 2007

Stress testing (microhydraulic fracturing) is recognized by the petroleum industry as the most direct method of determining the minimum in-situ (closure) stress for a given reservoir rock and the surrounding formations. In general, it is variations of in-situ stress between formations that dominates hydraulic fracture height growth and overall fracture geometry. Misleading interpretations of stress-test data (cased or openhole) can lead to significant errors in the prediction of stress contrast between the producing and bounding rock layers as well as an erroneous estimation of closure stress in the productive interval. In either case, hydraulic-fracture-treatment designs based on this information may not be designed optimally, and the subsequent interpretation of the fracturing treatment pressure response may not be correct. We present an evolutionary approach in the analysis of stress-test data that leads to more consistent results relating directly to actual fracture-treatment pressure responses. Although the emphasis in this paper is on cased-hole stress-test-data interpretation, the methodology presented is also applicable to openhole stress testing and larger-scale pump-in/shut-in (i.e. calibration or minifracture) pressure falloff responses.
Estimating Reserves and Success for a Prospect With Geologically Dependent Layers
Authors: Murtha J. A.
Published: December 2007

A drilling prospect with several potential pay zones is modeled. Analytical arguments involving conditional probabilities reveal that geological dependence has no bearing on either the expected number of successful layers or the expected combined reserves. Monte Carlo simulation sheds light on the dispersion of the reserve distribution. A case study of an offshore Louisiana prospect with three layers illustrates the principles described. The general approach outlined in this model of layered pay zones can be applied to other types of prospects having multiple components that may be related such as fault blocks. Moreover, in addition to reserves, we can address other measures such as capital investment or completion costs.
Mechanical Skin Damage in Weils
Authors: Morales R. H. , Brown E. , Norman W. D. , DeBonis V. , Mathews M. J. , Park E. I. , Brown R.
Published: December 2007

This study describes and quantifies a mechanical skin damage resulting from the redistribution of stresses caused by drilling a well in a permeable material. The damage is localized within a cylindrical ring centered at the well axis. The stresses (and related positive skins) increase with depth, angle of inclination, and production time. They rapidly fade with lateral radial distance. The damage becomes insignificant at a distance greater than four times the borehole radius (or elastic/plastic interface radius).
Robust Technique for Real-Time Closure Stress Determination
Authors: Wright C. A. , Weijers Leen , Minner W. A. , Snow D. M.
Published: December 2007

To achieve credible engineering estimates of fracture geometry, fluid efficiency, and potential risks of premature screen-out, the engineer must reliably history match the observed net-fracturing pressure. Measurement of net-fracturing pressure requires first, and foremost, a reliable estimate of the formation closure stress, to which the net pressure is referred.

This paper documents both the theory and several example field applications of a novel flow-pulse closure stress determination method. The flow-pulse technique requires only small changes in fracture treatment pumping schedule that can be accomplished at little to no extra cost, yet it allows a robust estimation of formation closure stress in real time. The flow-pulse technique involves pumping a small minifrac (usually with water) and then pumping small pulses (of about 5 bbl) of fluid during the pressure decline. There is a dramatic change in pressure response when flow pulses are pumped into an open fracture vs. a fracture that is already closed.
Simultaneous Measurements of Relative Permeability, Capillary Pressure, and Electrical Resistivity with Microwave System for Saturation Monitoring
Authors: Honarpour Matt M. , Huang David D. , Al-Hussainy Rati
Published: December 2007

Accurate relative permeability (kr) and capillary pressure (Pc) data are essential for predicting the performance of hydrocarbon reservoirs. Traditionally, kr and Pc are measured independently in different experimental systems, and rarely on the same samples under identical conditions. However, because these properties can be very sensitive to the same variables, simultaneous measurements are needed for consistency and for rigorous modeling. It is also important to have the capability to establish field-observed initial water saturations in laboratory tests because relative permeability and capillary pressure during imbibition rely on the values of the initial water saturations.

A novel apparatus has been constructed to allow simultaneous measurements of capillary pressure, relative permeability, and electrical resistivity on cores up to 2" diameter and 6" long. Fluid saturation profile is monitored by a state-of-the-art microwave technique. A microwave scanner moves along the core, and in-situ fluid saturation is calculated from the transmitted signal intensity. This method does not require tagging fluids which may affect wetting properties. The apparatus can reduce water saturation to a low initial value and can operate at moderate temperature, overburden stress, and fluid pressure. It is equipped with an in-line viscometer for continuous and accurate monitoring of oil viscosity. In this paper, the unique features of the apparatus is presented, along with some capillary pressure and relative permeability data measured simultaneously at elevated temperature and pressure for illustration.
Characterization of Reservoir Core using Computed Microtomography
Authors: Coles M. E. , Hazlett R. D. , Spanne P. , Muegge E. L. , Furr M. J.
Published: December 2007

X-ray tomography is often utilized to evaluate and characterize structural characteristics within reservoir core material systems. Generally, medical computed tomography (CT) scanners have been employed because of their availability and ease of use. Current spatial resolutions of conventional medical CT scanners have, however, not allowed their use in obtaining pore level characterizations for most core samples. Recently developed high resolution computed microtomography (CMT) using synchrotron radiation x-ray sources is analogous to conventional medical CT scanning and provides the ability to obtain three dimensional characterization of specimens with a spatial resolution on the order of microns. Application of this technique to the study of core samples provides excellent two and three dimensional high resolution description of pore structure and mineral distributions. Statistical and variogram analysis of the microtomographic images provide descriptors characteristic of the specific core material. Pore space interconnectivity is accurately characterized and visualized. Pore level endpoint saturation microtomograms obtained during a core flood of a sandstone sample are presented.
On the Sensitivity and Spatial Resolution of Transient Pressure and Tracer Data for Heterogeneity Characterization
Authors: Datta-Gupta Akhil , Vasco D. W. , Long J. C. S.
Published: December 2007

This paper examines the sensitivities of interwell tracer and transient-pressure response to spatial distribution of permeability heterogeneity. On the basis of these sensitivities, we describe a formalism to quantify the resolution and spatial averaging associated with estimates of permeabilities derived through inversion of tracer and/or pressure data. The resolution is a measure of the effectiveness of the data in estimating local-scale (gridblock) permeabilities. The spatial averaging kernels quantify the inherent averaging associated with our estimates because of limited data or sampling. By examining the resolution and averaging kernels as a function of various data types, we can evaluate quantitatively the relative importance of tracer vs. pressure data for heterogeneity characterization and the improvement in estimates obtained by combining the data types. We illustrate the concepts by application to transient-pressure and tracer response from five-spot patterns and also to an experimental tracer response from a well-characterized slab of Antolini sandstone. Tracer data is found to yield much better resolution compared to transient-pressure response. Also, both transient-pressure and tracer data appear to resolve barriers to flow better rather than channels to flow.
Full-Field Reservoir Modeling of Central Oman Gas-Condensate Fields
Authors: Leemput L. E. C. van de , Bertram D. A. , Bentley M. R. , Gelling R.
Published: December 2007

Gas reserves sufficient for a major export scheme have been found in Central Oman. To support appraisal and development planning of the gas and condensate fields, a dedicated, multidisciplinary study team comprising both surface and subsurface engineers was assembled. The team fostered a high level of awareness of cross-disciplinary needs and challenges, resulting in timely data acquisition and a good fit between the various work activities. A field-development plan was completed in March 1994. The foundation of the subsurface contributions was a suite of advanced full-field reservoir models that were used to do the following.

Provide production and well requirement forecasts. Quantify the impact of uncertainties on field performance and project costs. Support the appraisal campaign. Optimize the field-development plan. Derive recovery factor ranges for reserves estimates.

The models were constructed early during the study, initially with general data with large uncertainty ranges and gradually refined with new appraisal data. This ultimately resulted in more than 20 full scenarios, quantifying and ranking the remaining uncertainty ranges. Geological/petrophysical uncertainties were quantified by use of newly developed, 3D probabilistic modeling tools. An efficient computing environment allowed a large number of sensitivities to be run in a timely, cost-effective manner.

The models also investigated a key concern in gas-condensate fields, well impairment caused by near-well condensate precipitation. Its impact was assessed by use of measured, capillary-number-dependent, relative permeability curves. Well-performance ranges were established on the basis of equation-of-state (EOS) single-well simulations and translated into the volatile-oil full-field models with pseudorelative permeability curves for the wells. The models used the sparse available data in an optimal way and, as part of the field-development plan, sustained confidence in the reserves estimates and the project, which is currently in the project specification phase.
Mass Transfer From Bypassed Zones During Gas Injection
Authors: Burger J. E. , Mohanty K. K.
Published: December 2007

Gasflooding in oil reservoirs leads to bypassing of the oil as a result of gravitational, viscous, and/or heterogeneity effects. A part of the bypassed oil can be recovered by the flowing solvent because of crossflow/mass transfer. In this work, we studied the effect of the orientation of the bypassed region and the enrichment of the solvent on the mass transfer. Laboratory-scale mass transfer and coreflood experiments were conducted. Numerical simulation was used to identify the role of the different mechanisms. Results indicate that the mass transfer is the least for the vertical orientation, intermediate for the inverted orientation, and the highest for the horizontal orientation. The mass transfer increases with enrichment for all orientations. Liquid-phase diffusion controls vertical-orientation mass transfer for the fluids studied. Gravity-driven flow contributes the most to the mass transfer in the horizontal and inverted orientations. Oil recovery in horizontal gasfloods can be nonmonotonic with enrichment. Multiphase flow in the near-miscible floods leads to less gravity override compared with the first-contact-miscible (FCM) floods.
Capillary Entrapment Caused by Small-Scale Wettability Heterogeneities
Authors: van Lingen P. P. , Bruining Johannes , van Kruijsdijk C. P. J. W.
Published: December 2007

Small-scale heterogeneities are abundant in oil reservoirs. It is well known that these heterogeneities can reduce the displacement efficiency of immiscible flooding because of capillary entrapment of oil. A typical heterogeneous facies is the laminated crossbed set with alternating high- and low-permeability laminae. Apart from this heterogeneity in grain size, the wettability of the laminae can also differ. The laminae can contain different minerals with different wetting characteristics, and wettability can be affected by adsorption of hydrocarbons to the grain surface. In this paper we focus on the effects of wettability on the entrapment. We describe a procedure that allows the reader to quantify the trapped oil saturation depending on absolute permeability, relative permeability, and capillary pressure curves of the foreset laminae, on the basis of a simplified crossbed geometry. The example calculations show the sensitivity of various parameters with respect to the magnitude of trapping.
Predicting Well-Stimulation Results in a Gas-Storage Field in the Absence of Reservoir Data With Neural Networks
Authors: Mohaghegh Shahab , McVey Dan , Aminian Khashayai , Ameri Sam
Published: December 2007

Selection of candidate wells for stimulation treatment to increase their productivity is a challenging task. A systematic approach that uses a three-layer backpropagation neural network, introduced in this paper, assists engineers in predicting post-stimulation well performance to select candidate wells for stimulation treatment. This approach can also be used to optimize the stimulation design parameters. Unlike conventional simulators that are based on mathematical modeling of the fracturing process, the process introduced in this paper uses no specific mathematical model. As a result, access to explicit reservoir data, such as porosity, permeability-thickness, and stress profile, is not essential. This is a major advantage over conventional hydraulic fracturing simulators, which can translate to considerable savings because it eliminates the need for expensive data collection. The application of this methodology to a gas-storage field is presented in this paper. The developed neural network can predict the postfracture well deliverability with approximately 95% accuracy. These results were achieved in the absence of reservoir data (permeability, porosity, thickness, and stress profiles) that makes conventional fracture simulation impossible. This process is currently being used to select candidate wells for future stimulation treatment in the aforementioned field.
A New Drillpipe Design Virtually Eliminates Failures That Result From Slip Damage
Authors: Wilson G. E.
Published: December 2007

Drillstrings made before 1982 were not designed to meet the rigorous demands of today's drilling. Deeper wells and higher-angle holes are requiring higher pump pressure, and more tensile and torque capacity. Back-reaming, with the use of a power swivel, is agitating these conditions even further.

Recent work has been done to improve the fatigue life of drillpipe by making drillpipe with longer internal-taper upsets and stress-relief grooves.

Even though improvements have been made, slip damage still takes its toll on drillpipe. This paper addresses the failures caused by slip damage and offers a solution for solving this problem. Finite element work and fatigue testing has been done to prove the effectiveness of this new drillpipe design.
Wellbore-Stability Analysis Made Easy and Practical
Authors: Santarelli F. J. , Zaho S. , Burrafato Giovanni , Zausa Fabrizio , Giacca Diego
Published: December 2007

Recent years have seen much scientific and technical progress in the understanding of wellbore stability. The main causes of instabilities have been identified, models have been developed, and practical remedies proposed and often tried successfully in the field. Yet despite this scientific effort, extra drilling costs associated with well-bore instabilities remain very high. This demonstrates that until now, scientific and technical progress has somehow failed to reach final technical and economical objectives.

This paper shows that the main reason for such a state of affairs is the complexity of wellbore-stability analysis, which cannot be performed for every single well on a worldwide basis. Having identified this, Agip undertook a vast effort of field-data back analysis to identify from historical records the best way to optimize its drilling planning, practice, and post-evaluation procedures. The paper presents part of this effort and in particular the back analysis of four clusters drilled in southern Italy (a total of 38 wells). It then draws conclusions for procedure optimization. Finally, it shows how the approach is used during the field-appraisal phase to speed up the learning curve and significantly cut the development-drilling costs.
An Analysis of Weep Holes as a Product Detection Device for Underground Compensated LPG Storage Systems
Authors: Sarica C. , Demir H. M. , Brill J. P.
Published: December 2007

Weep holes have been used widely to detect the presence of Liquefied Petroleum Gases (LPG) in brine for underground compensated storage systems. When the brine level drops below the weep hole, LPG product enters the brine production system causing an increase in both tubing head pressure and flow rate. To prevent cavern overfill, a cavern shutdown is initiated upon detection of LPG in the surface brine system by pressure or flow instruments at the tubing head.

In this study, we have investigated the multiphase flow characteristics of weep hole LPG detection systems to correctly estimate the operating limits. A simple and easy to use model has been developed to predict the tubing head pressure and flow rate increases. The model can be used to implement safer and more efficient operation procedures for underground compensated LPG storage systems.

The model predictions for a typical field case are presented. An analysis of weep holes as product detection devices for LPG storage reservoirs has been carried out. It was found that the increases in pressure and flow rates at the tubing head change as a function of injection flow rate of the product. Therefore, a thorough consideration of cavern operating parameters is necessary to evaluate the use constant pressure and flow rate values to initiate emergency shut down of the cavern.
Underbalanced Coiled-Tubing Drilling Experience on the Ula Field
Authors: Weighill Geoffrey , Thoreby Helge , Myrholt Lars
Published: December 2007

Underbalanced coiled-tubing drilling was identified as the best method to access additional reserves in the Ula oil field. The first operation involved deepening a live well through the existing production tubing with flow routed to the platform facilities. This was carried out simultaneously with other platform activity and the technical challenges, operational experience, and drilling performance are described. The operation was ultimately successful and the new hole section presently contributes an additional 700 STB/D of oil to the field production.
Rigless Multizone Recompletion Using a Cement Packer Placed With Coiled Tubing: A Case History
Authors: Nowak T. W. , Patout T. S.
Published: December 2007

Cement packers have been used for some time when reserve estimates have not justified the cost of major rig remedial work. They typically provide a means of zonal isolation of the last reserves in an existing wellbore. The success of these operations has historically been low. This is predominantly because of poor cement bonding in the annulus between the tubing and production casing. Because of the minimal amount of equipment on location and lack of upfront design work involved, most cement packers are doomed to failure before they are even placed. Cement packers have been placed using a large number of methods. In the Ship Shoal 181 field, Well B-4 would not economically justify a major rig workover, even though there were several uphole gas sands capable of producing in this well. With proper upfront planning and design, it would be economical; however, all these reserves could be produced in a through-tubing process using a cement packer.

This case history presents a refined look at existing technology involving placement of a cement packer and reviews problems common to cement-packer completions, including a case history. Solutions are also discussed for successfully completing and recovering reserves from not one but several remaining gas intervals. This paper reviews the design considerations and precautions, along with the production results and economics, for placing what is believed to be the largest cement packer placed through coiled tubing.
New pH-Buffered Low Polymer Borate Crosslinked Fluids for Hydraulic Fracturing
Authors: Nimerick Kenneth H. , Temple Harry L. , Card Roger J.
Published: December 2007

The utilization of low concentrations (15 to 20 lbm/1000 gal) of borate-crosslinked guar has not been successful in the past because of the inability to effectively control the pH and B(OH)−4 concentration of the fluid. Today's new pH buffer technology allows the use of low concentrations of guar at temperatures up to 210°F. These new pH-buffered borate-crosslinked guar fluids can be effectively utilized at temperatures up to 240°F by increasing the polymer loading. Due to the lower achievable polymer loading and relatively low pH, these new pH-buffered borate fluids possess excellent cleanup and retained proppant conductivity. In field documented cases, well cleanup times have been reduced by more than half. Laboratory conductivity tests show that these pH-buffered fluids, utilizing reduced polymer loading, produce retained conductivity values of 10 to 25% (absolute) higher than alternative conventional borate-crosslinked fluids incorporating higher polymer loading.