bluuebunny/crossref_metadata_2025 huggingface dataset:
Study of Vuggy Carbonates using X-Ray CT Scanner and NMR
Authors: Hidajat I. , Mohanty K. K. , Flaum M. , Hirasaki G.
Published: December 2007

Most existing permeability correlations for carbonates assume that vugs do not contribute to permeability. This may not always be the case, since vugs may be connected in some formations and contribute to the permeability. The objectives of this work are to identify vug connectivity by using X-ray CT scan and thin-section images of carbonates and to improve the NMR correlation for carbonates system. Six carbonate samples from Yates West Texas field were studied. Porosity and permeability of each sample were measured. The pore size distribution of these rocks is characterized by mercury porosimetry and NMR T2 measurements. Thin sections in the horizontal and vertical directions were prepared from the end pieces of the samples and were analyzed by using optical microscope. CT scanning of the core materials shows that porosity varies significantly along the core length. Some samples also show very distinct preferentially flow path, which affected the oil recovery. As revealed by the thin section analysis, the permeability of the samples studied is controlled either by the intergranular porosity or by the small channel that connects different vugs. The results of capillary pressure and NMR T2 measurement shows multimodal pore throat and pore body size distributions. The permeability is estimated by using effective medium approximation. All parameters used in effective medium approximation are derived from NMR T2 distribution by fitting with trimodal Weibull distribution. A better understanding of the contribution of vugs to permeability of carbonates is developed from this study.
Wettability, Saturation, and Viscosity Using the Magnetic Resonance Fluid Characterization Method and New Diffusion-Editing Pulse Sequences
Authors: Freedman R. , Heaton N. , Flaum M. , Hirasaki G. J. , Flaum C. , Hürlimann M.
Published: December 2007

This paper discusses a new nuclear magnetic resonance (NMR) method that can provide wettability, saturation, and oil viscosity values in rocks partially saturated with oil and brine. The method takes advantage of two new technological advances in NMR well logging — the MRF* Magnetic Resonance Fluid Characterization Method and NMR "diffusion-editing" (DE) pulse sequences. We discuss the principles underlying the fluid characterization method and the pulse sequences. The fluid characterization method is used to provide robust inversions of DE data suites acquired on fully brine-saturated and partially saturated rock samples. The outputs of the inversion are separate diffusion-free brine and oil T2 distributions for the fluids measured in the rocks.

NMR measurements on partially saturated rocks are sensitive to wettability because of surface relaxation of the wetting phase fluid. The surface relaxation rate, however, must be significant compared to the bulk relaxation rate in order for wettability to noticeably affect the NMR response. We present results showing that the surface relaxation rate at lower wetting phase saturations is enhanced compared to that measured at higher saturations. The consequence of wetting-phase saturation on NMR-based wettability determination is discussed. Wettability affects the relaxation rates of both the wetting and nonwetting phases in partially saturated rocks. Surface relaxation of the wetting phase in a rock results in shorter relaxation times than would otherwise be observed for the bulk fluid. The nonwetting phase fluid molecules do not come into contact with the pore surfaces and therefore their relaxation rate in the rock is the same as in the bulk fluid.

We present accurate and robust computations of diffusion-free T2 relaxation time distributions for both the wetting and nonwetting phases in four rocks that include two sandstones and two dolomites. A DE data suite was acquired on each rock measured in two different partial saturation states and also fully brine saturated. Wettability is determined by comparing the oil and brine T2 relaxation time distributions measured in the partially saturated rocks with the bulk oil T2 distribution and with the T2 distribution of the fully brine-saturated sample. The brine and oil T2 distributions are used to compute saturation and oil viscosity values.

A general discussion elucidating the sensitivity range and T2 limits of diffusion-based NMR methods is given in the appendix. The appendix also derives and displays the gain in signal-to-noise ratio that is achieved by using DE data sequences for fluid characterization in place of Carr-Purcell-Meiboom-Gill (CPMG) data suites.
Testing Conventionally Untestable High-Flow-Rate Wells with a Dual Energy Venturi Flowmeter
Authors: Oyewole A. A
Published: December 2007

Evaluating the productivity of a well through well testing is an essential aspect of managing production operations and reservoir recovery. When the reliability of gas, oil, and water flow rates is challenged by common events such as flow rates beyond the separator capacity or oil-water emulsions, the value of the well test can be severely diminished or even negative. Action taken or not taken as a result of an erroneous well test result can be counter to the production objectives and costly to the reservoir recovery.

This paper documents the use of a mobile dual-energy multiphase venturi flowmeter to test high-pressure and high-flow-rate wells in an offshore Nigeria field. Problematic fluid properties and challenging separation conditions limited the capabilities of the test separators to adequately measure the flow rates of the individual phases of the well effluent. Reliable rate measurements were hindered by the well's high pressure and high flow rates and by the presence of oil-water emulsion, which made phase separation extremely difficult.

Examples of well tests performed with the flow meter demonstrate the benefits of robust measurement principles in these adverse conditions. The value of capturing the flow transients using a high-frequency dual-energy spectral gamma ray detector is also illustrated, as it allowed a better understanding of the behavior of fluid flow in the wellbore. The flowmeter data enabled production diagnostics. Based on the flowmeter information, recommendations to further investigate the sources of water entry into the wellbore were made.
Modeling of a Deepwater Turbidite Reservoir Conditional to Seismic Data Using Multiple-Point Geostatistics
Authors: Strebelle Sebastien , Payrazyan Karen , Caers Jef
Published: December 2007

Geological interpretation and seismic data analysis provide two complementary sources of information to model reservoir architecture. Seismic data affords the opportunity to identify geologic patterns and features at a resolution on the order of 10's of feet, while well logs and conceptual geologic models provide information at a resolution on the order of one foot. Both the large-scale distribution of geologic features and their internal fine-scale architecture influence reservoir performance. Development and application of modeling techniques that incorporate both large-scale information derived from seismic and fine-scale information derived from well logs, cores, and analog studies represents a significant opportunity to improve reservoir performance predictions.

In this paper we present a practical new geostatistical approach for solving this difficult data integration problem and apply it to an actual, prominent reservoir. Traditional geostatistics relies upon a variogram to describe geologic continuity. However, a variogram, which is a two-point measure of spatial variability, cannot describe realistic, curvilinear or geometrically complex patterns. Multiple-point geostatistics uses a training image instead of a variogram to account for geological information. The training image provides a conceptual description of the subsurface geological heterogeneity, containing possibly complex multiple-point patterns of geological heterogeneity. Multiple-point statistics simulation then consists of anchoring these patterns to well data and seismic-derived information. This work introduces a novel alternative approach to traditional Bayesian modeling to incorporate seismic.

The focus in this paper lies in demonstrating the practicality, flexibility and CPU-advantage of this new approach by applying it to an actual deep-water turbidite reservoir. Based on well log interpretation and a global geological understanding of the reservoir architecture, a training image depicting sinuous sand bodies is generated using a non-conditional object-based simulation algorithm. Disconnected sand bodies are interpreted from seismic amplitude data using a principal component cluster analysis technique. In addition, a map of local sand probabilities obtained from a principal component proximity transform of the same seismic is generated. Multiple-point geostatistics then simulates multiple realizations of channel bodies constrained to the local sand probabilities, partially interpreted sand bodies and well-log data. The CPU-time is comparable to traditional geostatistical methods.
Geostatistical Assignment of Reservoir Properties on Unstructured Grids
Authors: Deutsch C. V. , Tran T. T. , Pyrcz M. J.
Published: December 2007

Reservoir simulation is often performed on irregular nonCartesian grids. A common methodology for building the input reservoir models is to perform geostatistical reservoir models on a fine grid and then to average them to the coarser unstructured grid. This method is computationally expensive; a more efficient approach is to modify the geostatistical algorithms to directly populate the unstructured grid.

The required modifications are described in this paper. First, direct simulation must be used in place of the more common Gaussian simulation. This is required because reservoir properties do not average linearly after Gaussian transformation; averaging is required because each grid block potentially has a different volume. Second, volume averaged variogram or covariance values are required between two arbitrary blocks v1(u) and v2(u’). These must be calculated quickly and efficiently. Third, to maintain a reasonable speed of geostatistical simulation on unstructured grids a customized search and a non-stationary covariance lookup table of the average covariance between blocks is required. Finally, directional permeability requires a special transformation to account for the nature of averaging.

We present the implementation details and some results using tartan and radial grids.
Sensitivity Analysis of Petrophysical Properties Spatial Distributions, and Flow Performance Forecasts to Geostatistical Parameters Using Derivative Coefficients
Authors: Landa Jorge L. , Strebelle Sebastien
Published: December 2007

This paper presents a methodology to assess the relative impact of geostatistical parameters on reservoir property models and flow simulation results using sensitivity coefficients.

Petrophysical properties that are correlated cannot be simulated independently. To account for cross-correlation between properties such as porosity and permeability, common practice consists in using sequential workflows to construct reservoir models. Workflows are intricate combinations of geostatistical simulations and deterministic operations that proceed sequentially. The output of one particular step can serve as an input to several subsequent steps. Thus it is very difficult to determine which modeling parameters have the greatest impact on the final reservoir model. Yet, determining those most sensitive parameters is critical for the Earth scientist to better allocate his time and modeling efforts.

Such sensitivity analysis should be performed from both a static and a dynamic perspective. First, we want to identify the parameters that affect most the spatial distribution of the petrophysical properties. Each parameter, e.g. the direction of anisotropy of the porosity variogram or the mean of the porosity distribution, is perturbed independently. Resulting changes in porosity and permeability distributions are mapped and analyzed. The most sensitive parameters are retained. Their impact on individual well performance and whole field production is then evaluated using a modified reservoir simulator that allows computing sensitivity coefficients. Although some linear assumptions are used, the static and dynamic sensitivity derivatives appear to provide a very powerful guide to prioritize reservoir-modeling steps.

In this paper, we apply that methodology to an actual reservoir located offshore of Nigeria with 75 wells and more than 30 years of production history.
Openhole Gravel Packing — An Evolving Mainstay Deepwater Completion Method
Authors: Grigsby Tommy , Vitthal Sanjay
Published: December 2007

Operators have found that by integrating drilling and completion techniques, they can develop a highly reliable openhole horizontal gravel-pack completion that can control sand production and produce hydrocarbons at a high-rate. Because of the success of this methodology, it has become a mainstay completion technique in the deepwater developments in Brazil and has shown the same potential for upcoming deepwater developments in West Africa.

This paper will discuss the evolution of the integrated concepts, the "lessons learned" that are being used to increase the scope of application, and how new techniques are enhancing reliability for these completions. Specifics include advances that eliminate openhole tortuosity in openhole drilling techniques, new downhole tools that can reduce risk as well as completion cycle time, and improvements in gravel pack fluids.

These advances are continuing to push the technological envelope. The new technological benefits are: Reduced completion cycle time, thereby reducing completion costReduced formation damageImproved completion reliability throughout the potential life of the well.
An Integrated Experimental and Numerical Approach to Assess the Performance of Solvent Injection into Heavy Oil
Authors: Dauba C. , Quettier L. , Christensen J. , Le Goff C. , Cordelier P.
Published: December 2007

Injection of gaseous solvent in heavy oil reservoirs is considered as an alternative recovery technique to thermal processes. The feasibility and performance of this technique, although numerous issues remain, are assessed at the macroscopic scale through an integrated approach in four steps. This paper describes: The design of the optimum solvent composition: Thermodynamic simulations were carried out to obtain the composition of the relevant solvent, which must be gaseous and close to miscibility under reservoir conditions. The following composition was achieved: 80%C2 and 20% C3.The PVT analysis of both reservoir oil and several mixtures with injected solvent: Results of the PVT experiments carried out to characterize the multi-phase behavior, the evolution of viscosity and density versus the amount of injected solvent are presented. A Peng Robinson equation of state, tuned on one of the oil-solvent mixtures, predicts correctly the properties (Psat, GOR, density) of the other ones. On the other hand, the usual Lohrenz-Bray-Clark correlation underestimates the viscosity decrease of the saturated oil.The design of the long core experiment: the injection rate for a stable displacement is determined according to the conclusions of simulations performed both in 1D and 2D. Finely gridded 2D simulations are carried out to investigate the effect of small-scale heterogeneity and show some fingering of the diluted oil into the original heavy oil.The core flood experiment under reservoir conditions: Solvent is injected top-down into an unconsolidated 35-cm long core. New insights into recovery, oil and solvent produced rates, GOR and composition of produced oil versus time are reported. The saturation profiles monitored by 1D X-Ray source are consistent with a gas-drive stabilized by capillarity.

Conclusions about the main mechanisms involved in this solvent coreflood are presented; they should be confirmed by the history match of the experimental results.
Effects of Non-Darcy Flow on Pressure Transient Analysis of Hydraulically Fractured Gas Wells
Authors: Alvarez Cesar H. , Holditch Stephen A. , McVay Duane A.
Published: December 2007

Conventional well-testing techniques are commonly used to evaluate pressure transient tests of hydraulically fractured gas wells to estimate values such as formation permeability, fracture half-length, and fracture conductivity. When non-Darcy flow occurs along the fracture, analysis of the pressure transient test data using conventional analyses methods will produce incorrect values of fracture conductivity and fracture half-length.

This work emphasizes the importance of non-Darcy flow in the hydraulic fracture and its effects on pressure buildup analyses of hydraulically fractured gas wells. A reservoir simulator was used to generate pressure drawdown and buildup data both with and without the effects of non-Darcy flow. These synthetic buildup tests were then analyzed using conventional well-testing techniques. We found that when non-Darcy flow occurs along the fracture, the estimated fracture conductivity and fracture half-length represent only a small fraction of the actual values. Also, the degree to which the non-Darcy flow affects the well-test results depends upon the values of fracture permeability, water saturation inside the fracture, and the production rate during the drawdown period. If the incorrect fracture properties obtained from conventional analysis are used in reservoir simulation forecasting, critical values such as production rate and total recovery will be miscalculated.

Since conventional well-test analysis cannot be used to determine fracture parameters reliably, simulation history matching is the only appropriate method to correctly analyze buildup pressure response from hydraulically fractured wells in gas reservoirs.
Practical and Successful Prevention of Annular Pressure Buildup on the Marlin Project
Authors: Vargo Richard F. , Payne Mike , Faul Ronnie , LeBlanc John , Griffith James E.
Published: December 2007

In late 1999, British Petroleum (BP) experienced a well failure in the Marlin development in deepwater Gulf of Mexico (GOM). Within hours of starting production, the production tieback casing collapsed, causing failure of the production tubing. Pressurization of outer annuli due to production thermal effects was identified as one of two possible root causes of the failure.

The oil and gas industry has been observing, documenting, and reporting cases of annular pressure buildup (APB) in annuli for several years.1 On land, platform, and spar-type wells having access to annuli, the problem can usually be dealt with by bleeding off the annular pressure as needed. Subsea completions, however, do not allow this capability, and the technology to provide access is still being studied. Especially susceptible to APB are deepwater developments in which the differential between mudline temperatures and flowing-production temperatures can exceed 125° to 200°F.

A key technique developed during the Marlin project to help prevent APB was the use of nitrified cementing spacers. These spacers provide a compressible cushion that can absorb the pressurization effects caused by thermal heating in the annulus. In addition to carrying nitrogen, the spacers can also provide adequate mud removal and remain stable for at least 72 hr. These features help prevent the migration of nitrogen into the riser prior to setting the wellhead seals. Based on a series of pressure/volume/temperature (PVT) tests and well design simulations, the minimum foam quality of nitrogen was determined.

Service company and operator engineering staffs worked proactively and integrated their efforts to identify, evaluate, plan, and implement multiple options for resolving this substantial well-integrity issue. This paper reviews the problems associated with APB, details the large-scale testing that was conducted, and the resulting best practices that help prevent APB from affecting the casing design. These best practices were successfully implemented on the Marlin subsea development, and other projects are also using these techniques.
Application of Transient Multiphase Compositional Tracking for Pipeline Flow Analysis
Authors: Rydahl Allan
Published: December 2007

This paper details the application of transient multiphase compositional tracking in a pipeline flow simulation study. Comparisons of results between the compositional modeling approach and results obtained using a precalculated table-based fluid property approach is presented. Both simulation models are based on the dynamic two-fluid theory commonly used to simulate transient multiphase flow in wells and pipelines. When comparing the simulation results with pipeline depressurization field data for one field case, the gas outlet rate and pressure is simulated with greater accuracy using the compositional tracking approach. For a second field case the simulation results are comparable for gas outlet rates and pressures although the compositional tracking overall is better. For liquid volumes the results are of comparable quality for both field cases.
Experimental Research on Downward Two-Phase Flow
Authors: Hernandez Ali , Gonzalez Leonor , Gonzalez Pedro
Published: December 2007

There are several applications in the Oil Industry where it is necessary to be able to predict the pressure drop in downward two-phase flow. One of these applications has to do with recent developments on simultaneous water and gas injection projects for reservoir pressure maintenance purposes. In order to be able to properly design surface facilities for the simultaneous injection of natural gas and water, a fairly good estimate must be made on the surface injection pressure required for a desired down-hole injection pressure. Unfortunately, there are very few correlations available in the literature that can be used for downward two-phase flow. Furthermore, field scale data that can be used to test these correlations is not available, so their predictive power is unknown.

In order to gain insight on pressure drop, flow patterns and liquid hold-up expected in downward two-phase flow, an experimental work was performed using 2 in I.D. pipes with water and air as process fluids. The experimental results are presented in this paper, together with a comparison of these results with the predictions of currently used correlations.
A General Scaling Method for Spontaneous Imbibition
Authors: Li Kewen , Horne Roland N.
Published: December 2007

Scaling the experimental data of spontaneous imbibition without serious limitations has been difficult. To this end, a general approach was developed to scale the experimental data of spontaneous imbibition for most systems (gas-liquid-rock and oil-water-rock systems) in both cocurrent and countercurrent cases. We defined a dimensionless time with almost all the parameters considered. These include porosity, permeability, size, shape, boundary conditions, wetting and nonwetting phase relative permeabilities, interfacial tension, wettability, and gravity. The definition of the dimensionless time was not empirical, instead, was based on theoretical analysis of the fluid flow mechanisms that govern spontaneous imbibition. The general scaling method was confirmed against the experimental data from spontaneous water imbibition conducted at different interfacial tensions in oil-saturated rocks with different sizes and permeabilities. A general analytical solution to the relationship between recovery and imbibition time for linear spontaneous imbibition was derived. The analytical solution predicts a linear correlation between the imbibition rate and the reciprocal of the recovery by spontaneous imbibition in most fluid-fluid-rock systems.
Forecasting Liquid Condensate and Water Production In Two-Phase And Three-Phase Gas Condensate Systems
Authors: Jokhio S. A. , Tiab D. , Escobar F.
Published: December 2007

This paper shows how to forecast liquid condensate and water production from gas and gas-condensate wells. The methodology is based on the Whitson and Fevang's5 method of handling fluid properties using two-phase pseudopressure function that not only takes into account the pressure dependence of the fluid properties but also retrograde behavior (phase change) of light hydrocarbons in the reservoir. Tedious mathematical treatment indicates that the oil phase production can also be predicted using the surface gas production in case of two-phase, and gas and water production data in case of three-phase producing wells.

To establish Inflow Performance, one needs relative permeability data along with PVT data. In this study, we have used pressure transient methods to obtain the effective permeability as a function of pressure. Once the correlation between the effective permeability and pressure is obtained, it is used in the pesudopressure integral. Sapphire well test simulator was used to simulate pressure test data and PVT data for condensate wells. The effective permeability correlation was developed from the well test analysis. This was done by simulating 2-phase and 3-phase gas-condensate reservoirs with reservoir pressure equal to P*.

The main source of the liquid condensate is considered the 1st region, closest to the wellbore, which is spread areally between the wellbore and the pressure P*, in the reservoir. Flow in this region is two phase in nature. Some of the liquid phase may go into the gas phase due to retrograde conditions if exist. Region-2 consists of liquid and the gas phase but it is assumed that the liquid condensate is immobile since the liquid saturation has not builtup enough to initiate flow. The pressure range in this region is from Pd to P*. The water production, however, is the contribution of the entire reservoir since no phase change is expected in the aqueous phase. More importantly, water phase is considered as the most reliable phase in gas condensate systems from engineering point of view, since water properties hardly change with pressure in the reservoir.

Two examples are solved with simulated data to show the use of the technique developed.
Real Options Applied to Selection of Technological Alternative for Offshore Oilfield Development
Authors: Dezen Francisco , Morooka Celso K.
Published: December 2007

The future outcome of a project is not usually predictable, and therefore uncertainty plays an important role into the process. Current economic models that support decision-making process are not always capable of indicating and accounting for the benefits of flexible field development plans.

One way to resolve this is to add real options valuation (ROV) into the economic model and to expand the decision-making process to accommodate this technique. The work presented on the paper describes a methodology that incorporates ROV into the analysis of different field development alternatives for deepwater.

Examples are presented in this paper to demonstrate that there is a difference in the total value of the projects when flexibility is accounted for. It is also highlighted the different manners that flexibility contributes to the project value and how to model a field development plan in order to analyse its flexibility.
New Approach for Interpreting Pressure Transient Test After Massive Acidizing Treatment
Authors: Valkó Peter P. , Mursal Fnu , Vance Harold
Published: December 2007

Interpreting a pressure transient test of an acidized well in the framework of the thin skin concept is not straightforward for several reasons. First, the effect of stimulation cannot be considered to be localized in an infinitesimal region near the wellbore. Second, even if an equivalent skin factor can be defined, it will not be constant during the transient period. Third, the negative skin does not allow for a rigorous solution of the transient problem in the presence of wellbore storage and hence type curves can be generated only using "equivalent" fractured well models.

In this paper we introduce a theoretically rigorous approach for the case when the effect of stimulation (or, as a matter of fact, damage) can be represented as a power-law variation of the permeability (as a function of the radial distance from the well). The well-reservoir system is described with three parameters: the areal average permeability, the power-law exponent (positive for damaged and negative for stimulated wells) and the wellbore storage coefficient. To our knowledge first in the technical literature, the model is solved rigorously in Laplace space. Using numerical inversion, type curves are generated. The interpretation methodology is illustrated with field cases.
Well Construction Efficiency Processes Yielding a Significant Step Change
Authors: Wylie Glenda , Zamora Frank , Terry Jim , Murali B. N.
Published: December 2007

In the past, serial drilling operations have been employed for the conventional well-architecture construction process. In this paper, new technological advancements from initial design planning to execution processes will be discussed. These advancements produce a "step-change" well architecture with a uniform well diameter and fullbore production delivery conduit called a monowell. From the well-construction processes to the "end" product, efficiency is driven in the technologies and processes described.

Technical improvements in mechanical and chemical solutions can help achieve a well architecture with a uniform diameter in reduced serial operations. Technological advancements in the areas of composite technology and realtime downhole monitoring can enhance deployment efficiency compared to conventional methods. The efficiency processes yield a well architecture with more efficient reservoir penetration and oil-production delivery by: Reducing formation/reservoir evaluation time and well placement through better methodsIncreasing penetration rateReducing the volume of drill cuttings and the oil content contained on the cuttingsReducing fluid requirements (i.e. drilling fluids and cements)Reducing casing size and the number of casing strings requiredReducing overall rig timeReducing overall flat timeImproving well productivityReducing required horsepower and rig size

The unique design and planning features of the monowell are discussed, including reservoir focus, geomechanics, and design requirements of drilling systems, formation evaluation equipment, fluid systems, and wellbore hardware. Multiple "uniform diameter" well-construction execution methods, including multiple deployment methods, are discussed. Together, the well-architecture change and execution-process changes result in a monowell with improved well construction design, execution, and production efficiencies. The monowell provides a significant industry step change in reducing cost per barrel of oil equivalent through improved efficiencies through a multitude of technologies.
Mass Transfer of Methane into Oil for the Transportation of Gas and Oil Through a Single-Phase Pipeline
Authors: Tang Joseph S , Zhang P. X.
Published: December 2007

Re-combining and transporting offshore produced gas and oil to onshore processing facilities through a single multi-phase pipeline is attractive for economic reasons. Multiphase pipeline is difficult to design and operate due to flow complexity, flow instability, uncertainty in liquid holdup and pressure drop; therefore, it has not been widely accepted in the industry. To avoid handling multi-phase problems, it is sometimes advantageous to operate the pipeline at above bubble point pressure so that gas can be re-dissolved into the oil and be transported in one phase. In addition, transportation of live oil with dissolved gas is a preferred option for waxy crude where gelling of the stock tank oil at reduced temperature is a problem. However, gas dissolution is not instantaneous because of finite mass transfer rate, a two-phase entrance region will exist, thus complicating the design of the pipeline. This paper studied the mass transfer characteristics of methane into light oil in a horizontal pipeline.

Depending on the Froude number and the gas-oil ratio, multi-phase flow can be characterized by three main flow regimes, namely, bubble, segregated and intermittent flow. Flow regime affects the interfacial contacting area as well as the mass transfer coefficient, thus the dissolution of gas into oil. Analytical solutions were derived to relate the rate of methane transfer into oil for the three flow regimes as a function of input gas-oil ratio, equilibrium GOR and pipe size. The model also predicted the length of the two-phase entrance region, i.e., the length required for complete dissolution of the gas. It was also found that inline mixing device was necessary to maintain dispersed flow for rapid transfer of gas into oil. The model agrees well with experimental results.
Optimization of Ramp-Up Operations in a Dual Large Diameter Long-Distance Subsea Wet Gas Pipeline System
Authors: Harun A. F. , Cochran S. W. , Choate T. G. A.
Published: December 2007

Ramp-up of large-diameter, long-distance production systems is challenging due to the large liquid holdups that can exist and the transient nature of ramp-up operations. This paper presents the results of multiphase simulations performed to optimize ramp-up operations in a subsea wet gas production pipeline system. All three phases (gas, condensate, and water) of the fluid system are considered. The pipeline system consists of dual interconnected, large-diameter (20+ in.) pipelines approximately 56 miles in overall length. The optimum ramp-up scenario is reached when the gas delivery rate can be increased in minimum time while maintaining the liquid surge within the onshore slug catcher liquid handling capacity. This paper proposes a solution to this problem and illustrates it with transient multiphase simulation results. The simulation results also provide some insight into the physics of the multiphase flow phenomena in large-diameter wet gas pipelines.
Resistivity Modeling of Array Laterolog Tools: An Application in an Offshore Norway Clastic Reservoir
Authors: Galli M. T. , Gonfalini M. , Mele M. , Belik P. , Faivre O. , Jammes L. , Litman A.
Published: December 2007

Resistivity logs, as directly used for the determination of Water Saturation profiles, have always been of focal interest for the oil industry; it's clear that the quality of these measurements, currently used in the net pay and hydrocarbon-in-place determination, must be very high. As a consequence, more accurate and flexible resistivity tools have been developed in recent years. We are addressing here the family of array tools, and especially the HRLA1, which makes available a set of 5 galvanic resistivity measurements at different depths of investigation.

Unfortunately, the most common types of environmental noise (borehole effects, shoulder bed resistivity contrasts, invasion, the presence of dips, anisotropy), still alter the measured resistivity, thus affecting the estimation of the true resistivity in hydrocarbon bearing levels.

In order to remove these alterations, Schlumberger, in cooperation with ENI-AGIP, has developed a 2D resistivity modeling & inversion technique that can simultaneously correct a number of environmental effects.

This paper presents the results obtained in two wells of a reservoir in the offshore Norway area where the sandstone bodies are interbedded with deltaic shales. The values of porosity and permeability are generally very high and a complete set of data (conventional & special core analysis, conventional wireline logs, microresistivity imaging logs, NMR, sedimentological analysis from core and images) is available.

The 2D modeling provided a better definition of the water saturation in the thinner sandstone bodies of the sequence and in the presence of anomalous invasion profiles.

When comparing the resistivity modeling results with those obtained by standard interpretation techniques, we can see the effectiveness of the developed methodologies (both hardware and software) in improving the reservoir characterization and in maximizing the return of the investments in logging and well data measurements.
Coupled Geomechanics and Reservoir Simulation
Authors: Thomas L. K. , Chin L. Y. , Pierson R. G. , Sylte J. E.
Published: December 2007

An iterative procedure is presented in this paper to couple geomechanics and reservoir simulation models for the simulation of weaker rock formations with complex constitutive behavior. Parallel computing is employed in the coupled model to reduce run time in the compute intensive geomechanics model. The procedures developed here are general and can be applied to any reservoir simulation and geomechanics model.

Field and example problems under a variety of exploitation scenarios are presented to demonstrate the utility and robust nature of the coupled model.
A Petrophysics and Reservoir Performance-Based Reservoir Characterization of the Womack Hill Smackover Field Alabama
Authors: Avila J. C. , Archer R. A. , Mancini E. A. , Haynes C. D. , Blasingame T. A.
Published: December 2007

The primary objective of this work is to perform a complete characterization of the Womack Hill (oil) Field in Southern Alabama using petrophysical and reservoir performance data — and to provide reservoir management strategies that lead to improved oil recovery at Womack Hill Field. The process for achieving this goal requires the following specific objectives: To develop correlations between the core and well log data in order to generate spatial distributions of reservoir properties such as: porosity, permeability, net pay, etc.To analyze the production history on a per well basis using the decline type curve technique which provides estimates of the following properties: —Oil-in-place (N),—Effective permeability (k),—Flow capacity (kh),—Reservoir drainage area (A), and—Near-well skin factor (5).To determine the Estimated Ultimate Recovery (or EUR) for each well using the historical production data. The EUR is used to establish the volume of recoverable oil-in-place.To draw conclusions and provide recommendations regarding infill drilling, well completions, and production practices based on the results of integrating the geological data and the production history analysis.
Improving Results of Coalbed Methane Development Strategies by Integrating Geomechanics and Hydraulic Fracturing Technologies
Authors: Johnson Raymond L. , Flottman Thomas , Campagna David J.
Published: December 2007

Hydraulic fracturing has been a key technology in the development of coalbed methane (CBM) resources worldwide. Obtaining adequate fracture length and conductivity has limited the ability to obtain adequate productivity improvement to further develop many small seams or stacked-seam reservoirs. Fracture complexity and growth out of the interval have frequently been cited as limiting factors in achieving optimal length in these types of intervals; however, the diagnostics to evaluate and model these effects have been limited. Finally, many of the past studies of hydraulic fracturing mechanics in coal have been focused on North American examples where normal faulting stress states are present, unlike many of the coal-producing basins worldwide and particularly in Eastern Australia.

Using examples from the Scotia Field, we describe how past and present stress framework analyses and post-frac treatment diagnostics were integrated to better describe the in-situ stress state. Through analyses of these examples, we qualify the inter-relationships of productivity to in-situ stress, pre-existing fractures, and observations from the induced hydraulic fractures. Finally, we describe cases where the hydraulic fracturing complexity and in-situ stress conditions lead to wellbore complications and observable rock-mechanical failures. The end result is a more predictive model, which is being used to develop this CBM resource.
Multilateral Technology as a Creative Reservoir Development Strategy for New and Mature Fields Alike
Authors: Oberkircher Jim
Published: December 2007

Mature fields and new developments. Very different operating arenas but a common objective: produce hydrocarbons as quickly and efficiently as possible. The challenges for today's operators are many: complex geologic conditions such as compartmentalized or stacked reservoirsdifficult reservoir conditions such as viscous fluids or tight formationshostile environments, whether deep water or frontier development areasefficient and effective management of the reservoir development process.

It is important now more than ever to look for new and innovative solutions to the problems and challenges facing us in all of these areas. Multilateral technology provides just such a solution.

Multilateral technology has been successfully applied in all of these areas and has had a dramatic, step-change impact in the financial results of many. The ability to deliver an optimal reservoir development plan has been demonstrated time and again; and, in the process, new ideas in terms of equipment and reservoir development strategies have emerged. The adage of "if you can draw it we can drill it" is now more of a reality than it has ever been before. These new abilities allow for creativity to be released and for improved results to be achieved. However, in order to achieve these results, it is important to break loose of the old, self-imposed limits that have been placed on us and free ourselves from the bonds of technical restrictions. Knowledge is the key that can unlock those chains.

Successful multilateral developments will be examined from around the world including the current multilateral hot spots of the South America, and the Deep Water of the North Sea. The impact of these advances on future field developments, both mature and new, will be examined in terms of operational accomplishments and economic success. This paper will also explore the potential of new, synergistic technologies and work processes and their impact on future field development strategies.
Designing an Injection Program of Produced Water Re-Injection in Mature Fields
Authors: Rudi Rubiandini Ria S. , Fitnawan Eko A. , Singh Kalwant
Published: December 2007

Production of oil & gas has very big influence to mankind civilization but the excessive generation of produced water in mature fields as a by-product may have bad impact to environment. Pollution of surface water supplies or fresh water aquifers has become a serious concern in recent years. It is therefore an obligation upon the industry to handle the produced water and disposed it responsibly. This concern has focused attention on produced water re-injection into underground formation (whether it is virgin or depleted reservoir) as a promising method to discharge oilfield water without polluting potable water supplies.

As refer to regulatory guidelines, injection well for produced water disposal must be operated so that the pressure during injection does not initiate new fractures or propagate existing fractures in the confining zone adjacent to the sources of drinking water, which could damage the receiving layer or cap rock. In order to achieve that purpose, the paper describes evaluations and planning on operational aspects regarding daily activity/practical operation, which are essential to the successful of water injection project. Operational aspect especially includes working pressure along the injection system, estimated formation fluid pressure as function of cumulative injected water, estimated fracture pressure and its relation to proposed injection rate. Operational window for injection must be developed to determine the range of allowable injection pressure and its relationship with the proposed injection rate.

The paper also describe a method to determine the life time of each proposed injection well which is the compilation from the result of operational design analysis and reservoir pressure builds up data from simulation results. This study is very useful to make injection programs and scenarios to extent the injection lifetime (e.g. scenario to add new injector wells).
Combined Perforation and Sand-Control Technique
Authors: Zhao Zhengchao , Sun Houli , Zhao Ping , Liu Xiangming , Zhang Jianjun , Qin Yanhong
Published: December 2007

Combined perforation and sand-control technique is a new technique combining the perforation and sand control which are performed in one operation. This technique will simplify the performance, save the operating cost, reduce the formation damage and improve the well productivity. With this technique, there is no residue in the wellbore, thus providing favorable conditions for later treatments to the oil wells. It was developed by Drilling and Oil Production Technology Research Institute of Liaohe Oilfield Company, PetroChina in 1996. In-door research, physical simulation, the testing of various physical parameters, the development and design of complex perforation charges and guns, more than 1000 single target experiments and 7 times of full gun experiments were performed during the developing period. All technical specifications meet the requirements of the design. Field tests have been preformed since October 1999. By the end of January 2002, 24 well/times tests have been carried out and good results were achieved. The tests show that it is a very effective sand-control method in oil wells.
Integral Sintered Metal-Fiber Screen Sand Control Technique
Authors: Dezhu Liu , Houli Sun , Xiangming Liu , Jianjun Zhang , Ping Zhao , Shaojin Cheng
Published: December 2007

The integral sintered metal-fiber screen (hereinafter called ISS screen) sand control technique overcame the weakness of long-term and difficult operation, high cost and difficult workover caused by gravel packing mechanical sand control, as well as the formation damage and short term of validity caused by chemical sand control. With its special technical advantages, this technology is developed rapidly and its application is continuously expanding. It has become a dominant sand control technique developed for solving sand producing problem during heavy oil thermal recovery in Liaohe Oilfield, which can be applied in the vertical wells, deviated wells, sidetrack wells, open-hole wells and horizontal wells. This technology has realized its standardization and systematization, resulting in a very good application effectiveness and benefits and also contributing a lot to increasing oil production for Liaohe Oilfield. This technology has been awarded the Chinese national patent and the first prize from CNPC for technological popularization.