bluuebunny/crossref_metadata_2025 huggingface dataset:
Interpretation of the Unusual Fluid Distribution in the Yufutsu Gas-Condensate Field
Authors: Ghorayeb Kassem , Firoozabadi Abbas , Anraku Toshiyuki
Published: December 2007

It is generally believed that at steady state, a heavy fluid mixture cannot float, without motion, at the top of a light fluid mixture in a cavity. The expectation is that because of pressure diffusion, segregation occurs with the light fluid at the top and the heavy fluid at the bottom. We present, for the first time, an extensive set of measurements in 5-km vertical wells in a large hydrocarbon formation of 1-km thickness with horizontal dimensions on the order of several kilometers that show a high-density fluid mixture at the top of a light-density fluid mixture at steady state. The data in the 5-km wells show liquid in the middle, and vapor at the top and bottom. In the hydrocarbon formation, there is a gradual decrease of density with depth.

A theoretical model based on the thermodynamics of irreversible processes is used to provide an interpretation of the unusual density variation vs. depth both in the hydrocarbon formation and in the long wells, as well as the unusual species distribution in the hydrocarbon formation. The results reveal that thermal diffusion (caused by geothermal temperature gradient) causes the segregation of heavy components in the subsurface fluid mixture to the cold side in the Earth (that is, the top), overriding pressure and molecular diffusion (Fickian diffusion). As a consequence of the competition of these three diffusion effects, a heavy fluid mixture can float at the top with a light fluid mixture underneath. In the past, thermal diffusion has been thought of as a second-order effect. For the fluid mixture in our work, thermal diffusion is the main phenomenon affecting the spatial density and species distribution.
The Effect of Completion Methodologies on Production in the Jonah Field
Authors: Eberhard Mike , Mullen Mike
Published: December 2007

Improvements in completion technology have continued to increase the industry's ability to economically extract hydrocarbons from very low permeability reservoirs. The Jonah field in southwest Wyoming is a classic example of a reservoir commercialized with newer completion technology. The Lance formation in the Jonah field consists of several hundred feet of stacked lenticular sands with a reservoir permeability to gas of less than 10 μdarcy, requiring hydraulic fracturing to be economic. Completion techniques have evolved over the years. In the past 4 years, two techniques have emerged as the predominant completion methods—induced stress diversion and flow-through composite fracture plugs. This study evaluates these different techniques with spatial sampling to compare each well to its offset wells and to identify the completion scheme that yields the best results on cumulative production. From this study, a clear best practice for completing wells in the Jonah field to maximize production was determined.
Field Validation of Transient Swab-Surge Response With Real-Time Downhole Pressure Data
Authors: Samuel G. Robello , Sunthankar Ashwin , McColpin Glen , Bern Peter , Flynn Tim
Published: December 2007

This paper describes the field validation results of the transient swab-surge model with real-time downhole annular pressure data. The maximum pressures encountered during tripping or reciprocation are indispensible for making appropriate well-completion decisions. The prediction of swab and surge pressures is of critical importance in wells in which the pressure must be maintained within narrow limits of the pore and fracture pressures. It also plays a major role in running casing, particularly with narrow annular clearances. For these critical cases, a fully dynamic model is required to better estimate the maximum pressures encountered.

This paper presents actual surge-and-swab field data collected with downhole-drilling-data measuring tools during tripping and circulating operations. These data were obtained from Alaska and North Sea wells with a range of hole diameters and different base-fluid muds. The data were compared and interpreted with steady-state calculations as well as a dynamic surge model, which includes the effects of fluid inertia and compressibility, wellbore elasticity, pipe axial elasticity, and temperature-dependent fluid properties.

The sampling rate was specifically increased to 2 seconds and, in some cases, 1 second. This prevents downhole data attenuations and captures the full waveforms more accurately. Different operations were included in the downhole-drilling-data measuring tool runs to cover swabbing, surging, reciprocation, and simultaneous pumping operations during tripping. Model predictions for downhole pressure behavior were in excellent agreement with the measured real-time downhole pressure data.
A New Wellbore Position Calculation Method
Authors: Chia C. R. , Phillips W. J. , Aklestad D. L.
Published: December 2007

A method for combining multiple wellbore surveys to obtain a single, composite, more accurate well position is described. Established methods for defining the wellbore position and its associated uncertainty rely on accepting the position obtained from the most accurate survey instrument used in each section of the wellbore. This position is then assigned an uncertainty based on the information from this single survey-instrument run. When a modern wellbore is constructed today, each section may be surveyed for position many times with one or more magnetic, gyroscopic, or inertial survey instruments. By statistically combining the wellbore positions obtained from all the survey instruments run in a given section of the wellbore, a new position, designated the "most accurate position" (MAP), is calculated. The main advantage of the MAP is that its uncertainty is smaller than that of any of the constituent surveys. The major benefits of this technique is facilitating drilling smaller targets at greater distances, allowing new wellbores to be drilled in closer proximity to existing wellbores while maintaining accepted safety clearance rules, and improving reservoir delineation.
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, BP plc experienced a well failure in the Marlin development in deepwater Gulf of Mexico. Within hours of starting production, the production tieback casing collapsed, causing failure of the production tubing. Pressurization of outer annuli because of production thermal effects was identified as the most likely cause of the failure.
Performance of the Sussex Area Tensleep Reservoirs
Authors: Blevins T.R.
Published: December 2007

Introduction

This is a report on the performance of three Tensleep sandstone reservoirs located within an area of 6 sq miles in Meadow Creek and Sussex fields, Johnson County, Wyo. The fields are in the Powder River Basin near Linch, Wyo., which is 8 miles northeast of the Salt Creek field. The surface location of these reservoirs is shown in Fig. 1.

The Sussex field was discovered in July, 1948. There are three separate producing areas including the West Sussex, Sussex, and Meadow Creek fields in the general Sussex area. At the present time there are over 350 producing wells completed in seven producing horizons varying in depth from 3,000 to 9,200 ft.

The initial Tensleep discovery was in June, 1951 in the Sussex Unit A area. The initial Tensleep discoveries in the Meadow Creek Unit and in the Sussex Unit B areas were in March and June, 1952, respectively. Due to market allowables, development of these reservoirs was somewhat restricted until the latter part of 1953. Development since that time has continued on 40-acre spacing in each reservoir.

The Sussex Unit Tensleep A reservoir is approximately 1 ¼-miles long and ½-mile wide. The Sussex Unit Tensleep-Amsden B reservoir is approximately 2 ½-miles long and 1 ½-miles wide. The Meadow Creek Unit Tensleep reservoir is approximately 2-miles long and 2-miles wide.

It will be the purpose of this paper to discuss basic reservoir and geological characteristics, past performance and producing problems of these Tensleep reservoirs. The three reservoirs will be discussed separately in each section in order to bring out similar basic characteristics, as well as to show the contrast in individual reservoir performance. Future performance predictions have been made, but because of the relatively short producing history, they will be discussed only from an academic viewpoint.

Development

Sussex Unit Tensleep A

The Tensleep A discovery well was completed in June, 1951, for a natural flowing potential of 585 BOPD. Development continued on 40-acre spacing, and seven wells have been completed in the reservoir. All wells are open-hole completions and the reservoir is fully developed. The original water-oil contact was at an elevation of –4,330 ft mean sea level as determined lay drill-stem tests and production data.
A Comparison of Various Numerical Wave Prediction Techniques
Authors: Resio D. T. , Vincent C. L.
Published: December 2007

In recent years, the number of wave prediction models has increased greatly. These models range from relatively simple parameterizations of significant wave height as a function of wind, duration, and fetch to rather sophisticated solutions for the generation, propagation, and dissipation of two-dimensional (2D) wave spectra. It sometimes is suggested that any wave model will provide reasonable answers when properly applied, and that most of the deviations between measured waves and predicted waves can be explained by discrepancies between actual and estimated wind fields. Although much of the error in wave prediction almost certainly is related to problems in determining a wind field, this paper examines the specific question of whether there are differences among these models such that even if the wind field were specified perfectly, there would remain significant deviations among predicted waves. First, wave generation under uniform wind fields is compared by use of nondimensional parameters. Then the models are compared again under conditions of time-varying, space-varying wind fields and with irregular fetch boundaries.

We concluded that, in the open ocean with a long-duration, slowly varying weather system, most models produce similar results; however, near a coast or in regions with rapidly varying weather systems, marked differences can be expected from the use of different models.
Performance of the Leduc D-3 Reservoir
Authors: Horsfield R.
Published: December 2007

The Leduc D–3 pool was discovered in 1947 at a depth of 5,300 ft and is one of Canada's major oil fields. The relatively thin oil zone covers an area of 21,640 acres and originally contained more than 400 million bbl of oil in place. It is overlain by a large gas cap and underlain by more than 900 ft of water-bearing reef.

The history of this pool has been outstanding in many ways. The early behavior of the reservoir was dominated by the effects of a wild well which blew oil and gas for six months. Subsequent history indicated that the recovery mechanism consisted almost entirely of gas cap and water drives; however, during 1953, an increase in the rate of pressure decline indicated interference by neighboring pools through a common aquifer. A cooperative committee including almost all Leduc D–3 operators was formed and water injection was instituted in Sept., 1955, to maintain the reservoir pressure and eliminate further shrinkage losses. This project is unique in that pressure is being maintained uniformly throughout the pool with the use of only one injection well which is capable of taking more than 65,000 B/D on vacuum. After one-quarter of the oil in place had been produced, the increase in gas-oil ratio was slight and only one of 535 wells had been abandoned. This pool saw the first application of tubing-submergence completions in Canada and these wells, like most of those completed in a more conventional manner, are still capable of flowing production at rates in excess of 100 B/D without harmful effects.

Introduction

Discovery of the Leduc field in 1947 made oil history in Canada. After more than a decade of fruitless wildcatting in Southern Alberta and Saskatchewan, exploration activity moved northward and Imperial Leduc 1 was spudded 12 miles southwest of the City of Edmonton in Central Alberta.
Using Well Windows in Full-Field Reservoir Simulation
Authors: Mlacnik M. J. , Heinemann Z. E.
Published: December 2007

This paper presents the general and practical applicability of the "windowing technique"1 to model wells in full-field reservoir simulation. Windows modeling the near-wellbore area and the wellblock itself, constructed by the Perpendicular-Bisectional (PEBI) or k-orthogonal PEBI (k-PEBI) method, will be introduced for all wells of a reservoir or for selected "problem wells."

The windowing technique, introduced by Deimbacher and Heinemann,1 allows a time-dependent replacement of grids for a defined area during a simulation run. A window can represent any kind of well with a gridded wellbore and an appropriate grid pattern around the well. Such an approach makes the generally used Peaceman well model superfluous. Because the gridded wellbore and the gridblocks around it are small (some cubic feet), the computational stability requires small timesteps and a greater number of Newton-Raphson iterations. It is obvious that this is not feasible if the solution for the full-scale model and the well windows must be performed simultaneously. Therefore, in a first step, the fully implicit solution for the full-scale model will be calculated, but the inner blocks of the windows are solved for the pressure only, without updating the saturations and mole fractions. This solution provides the boundary influx for the windows. In a second step, the windows are calculated for the same overall timestep with up to 1,000 small local steps.

This paper presents the general and practical applicability of this method. Windows, constructed by the PEBI (k-PEBI) method, can be introduced automatically for all the wells (vertical, horizontal, and slanted) or for certain "problem wells."

For testing purposes, real case field models were used. It will be shown that the quality of the results obtained for the model calculated with integrated radial grids around the wells and small overall timesteps are equal to those obtained for the same model using the windowing and local timestepping techniques. Further, it will be shown that solving the window model with large timestep lengths for the first solution step and small lengths for the second solution step results in equal or smaller CPU times in comparison to the conventional model.
Gas Well Automation
Authors: Fitzgibbon H.J.
Published: December 2007

The design and operation of an automated gas flow and well control system is discussed. The system, designed to reduce operating costs and improve operating efficiency, presently controls 44 gas completions in the Bastion Bay field, Plaquemines Parish, in the marshes of South Louisiana. All wells are controlled from and connected with a central control station via buried multiconductor cable. The reasons remote control is desirable in this field are discussed, the design requirements are listed, the operation of the system is described and the advantages and disadvantages of the system selected are cited.

Introduction

There has been a recent growing tendency for oil companies to reduce or eliminate routine manual labor through the use of equipment designed to operate remotely, unattended and automatically. Systems are presently available for oil field use that can accomplish almost any desired function, limited only by the imagination of the engineer and the amount of investment a company wishes to make. It is the job of the engineer to selectively utilize systems that are practical in application and yet reasonable in cost. The primary function of any automation system is to increase operating efficiency and reduce operating costs. The object of this paper is to review the process by which automation equipment was selected for a large South Louisiana gas field, to describe the automation system selected and to outline its advantages and disadvantages.

Description of Field

Fig. 1 shows the geographical location of the Bastion Bay field, Plaquemines Parish, La. It is located in the Mississippi River delta area, approximately 70 miles southeast of New Orleans. Tenneco Oil Co., acting as operator for Tennessee Gas Transmission Co., operates 44 gas wells located within an area of approximately 8 sq miles. The field is located in a salt marsh adjacent to the Gulf of Mexico and is accessible only by boat. It is also approximately 12 miles from the nearest boat landing or supply point. All wells in the field were drilled from shallow-water, barge-mounted drilling rigs, and all wells are connected through a series of dredged access canals. Fig. 2 shows the field layout and location of the wells and canals. The water depth throughout the field is primarily dependent upon the tide, but ranges from 4 to 8 ft. In this field conservation units are formed about most of the wells, which result in varying working and royalty interests for each completion. Therefore, each gas completion produces through an individual heater and low temperature separation unit, and its production is separately metered. The condensate passes through individual positive volume meters and is then commingled into a condensate pipeline gathering system.

JPT

P. 873ˆ
IMPES Stability: The CFL Limit
Authors: Coats K. H.
Published: December 2007

This work considers cocurrent, 3D, single-phase miscible and two-phase immiscible, hyperbolic flow in a general grid, structured or unstructured. A given gridblock or control volume may have any number of neighbors. Heterogeneity, anisotropy, and viscous and gravity forces are included, while tensor considerations are neglected. The flow equations are discretized in space and time, with explicit composition and mobility used in the interblock flow terms [the IMPES (implicit pressure, explicit saturation/concentration) case].

Published stability analyses for this flow in a less general framework indicate that the CFL number must be < 1 or < 2 for stability. A recent paper reported stable 1- and 2D Buckley-Leverett two-phase simulations for CFL limits up to 2. A subsequent paper presented a stability analysis predicting a CFL limit of 2 for one of those simulations. This work gives a different reason for that stability up to a CFL limit of 2.

This work shows that the eigenvalues of the stability matrix are equal to its diagonal entries which, for any ordering scheme, are in turn equal to 1-CFLi.This leads to a conclusion of an early paper that CFL < 1is required for nonoscillatory stability. This paper discusses cases in which larger CFL limits between 1 and 2 exhibit stability, the existence or absence of applicable theory in such cases, and the practical contribution of such larger CFL limits to increased model efficiency.
Numerical Simulation of CO2 Leakage From a Geologic Disposal Reservoir, Including Transitions From Super- to Subcritical Conditions, and Boiling of Liquid CO2
Authors: Pruess Karsten
Published: December 2007

The critical point of CO2 is at temperature and pressure conditions of Tcrit = 31.04°C, Pcrit = 73.82 bar. At lower (subcritical) temperatures and/or pressures, CO2 can exist in two different phase states, a liquid and a gaseous state, as well as in two-phase mixtures of these states. Disposal of CO2 into brine formations would be made at supercritical pressures. However, CO2 escaping from the storage reservoir may migrate upward toward regions with lower temperatures and pressures, where CO2 would be in subcritical conditions. An assessment of the fate of leaking CO2 requires a capability to model not only supercritical but also subcritical CO2, as well as phase changes between liquid and gaseous CO2 in subcritical conditions. We have developed a methodology for numerically simulating the behavior of water/CO2 mixtures in permeable media under conditions that may include liquid, gaseous, and supercritical CO2. This has been applied to simulations of leakage from a deep storage reservoir in which a rising CO2 plume undergoes transitions from supercritical to subcritical conditions. We find strong cooling effects when liquid CO2 rises to elevations where it begins to boil and evolve a gaseous CO2 phase. A three-phase zone forms (aqueous/liquid/gas), which over time becomes several hundred meters thick as decreasing temperatures permit liquid CO2 to advance to shallower elevations. Fluid mobilities are reduced in the three-phase region from phase interference effects. This impedes CO2 upflow, causes the plume to spread out laterally, and gives rise to dispersed CO2 discharge at the land surface. Our simulation suggests that temperatures along a CO2 leakage path may decline to levels low enough that solid water ice and CO2 hydrate phases may be formed.
Geologic Hazards Related to Offshore Drilling and Construction in the Orinoco River Delta of Venezuela
Authors: Butenko J. , Barbot J.P.
Published: December 2007

This paper describes the results of a seabed and shallow stratigraphy reconaissance survey conducted offshore the Orinoco River delta in Venezuela. Several geologic features were encountered that may be hazardous to offshore drilling and construction.

Introduction

Since Dec. 1977, the Centro de Investigacion y Desarrollo (INTEVEP S.A.) of Petroleos de Venezuela S.A. (PDVSA) has been conducting a general geotechnical investigation in the Orinoco River delta region in cooperation with McClelland Engineers Inc.To assess the safety of oil drilling operations, this study has been carried out with these main objectives:define the basic geotechnical and geologic characters of the surficial sediments,identify the potential geologic hazards for drilling and future oil production, andgain an understanding of the sedimentary process and the recent geologic history of the area.

A high-resolution geophysical survey and a sampling program were conducted in the investigation area offshore the Orinoco River delta. A wide range of geotechnical, geologic, and chemical analyses were performed on the samples. As a base for the general understanding of the area of interest, a broad geologic study with emphasis on tectonics was carried out on a regional scale.

Methods of Study

The explored area covers 12,500 km of the continental shelf and the continental slope offshore the Orinoco River delta. The maximum water depth is 600 m, which is reached only in the northeastern part of the investigated area. Ninety percent of the geophysical lines were run in water depths between 10 and 200 m, the lowest limit corresponding to the limitations of the survey vessel (Fig. 1). Almost no investigation had been carried out before -in this region, and only limited data could help to define the geophysical grid. For this reason, it was decided to begin with a broad reconnaissance phase over a 10 × 10 km grid. These profiles provided general information that was used to define the most interesting areas that should be covered by a 5 × 5 km grid. Then, according to the data obtained, two main areas of high geologic complexity that seemed to be most hazardous to petroleum exploration were identified and surveyed with a 2.5 × 2.5 km grid.Accurate positioning was assured using an Argo DM 54(TM) range-range phase comparison system, with three fixed shore stations and a mobil station aboard the vessel. Generally, the accuracy of the system can be considered in the order of 10 m. Signal instability and loss of signals sometimes occurred at night, but only at great distances from the shore stations. Coarse checks were made periodically with a satellite system.

JPT

P. 764
Geology and Geotechnical Features of the Mid-Atlantic Continental Shelf
Authors: Demars K.R. , Charles R.D. , Richter J.A.
Published: December 2007

This paper summarizes and augments the existing geological and geotechnical engineering data on the U.S. mid-Atlantic continental shelf. This study provides a basis for planning and management for shelf users and for delineating research needs.

Introduction

Several major construction efforts are anticipated on the U.S. mid-Atlantic continental shelf over the next decade, including oil platforms and pipelines, deepwater ports, and power plants. In addition, there are many ongoing activities on the continental shelf, such as recreation, waste disposal, fishing, public safety, and defense. In each of these proposed efforts or ongoing activities, there is an interaction with the seabed of localized or regional nature. Preliminary information on the regional geology and sediment properties is needed for proper planning and management by shelf users and for delineating research needs. In fact, the National Research Council (NRC) Committee on Seafloor Engineering has acknowledged marine sediment studies to be of the highest priority for continental shelf development. Particular needs exist for soil maps and fundamental knowledge of the physical and engineering properties of marine sediments.The overall objectives are to summarize and improve existing geological and engineering shelf sediment information. Since the location of potential seabed developments are flexible, this study covers the general area off Delaware and extends from the beach to the shelf break. The primary objectives are (1) to assemble and interpret available geological and geotechnical data in view of possible engineering developments and (2) to obtain supplementary property data from laboratory tests. The laboratory tests were performed on samples acquired by the USGS during the recent continental margin boring program. It is the intent of this study to examine the general distribution of sediments and the unique aspects of engineering behavior. A brief review of the geology will provide a basis for examining the sediment property variations in addition to defining anticipated shelf development and construction hazards.

Delaware Continental Shelf

The continental shelf off Delaware is typical of the shelf along eastern North America. From a bathymetric map (Fig. 1) the shelf may be described as being broad and flat with a width of about 200 km (125 miles). The average slope is only 0.05 degrees, but many morphological features of the intermediate size, such as shoals or sand waves, exhibit locally steeper slopes of 2 or 3 degrees or more. In fact, very little of the outer-shelf topography reflects the morphology of coastal elements. The Hudson Channel and Canyon to the north of the Baltimore Canyon trough area is the only major feature that cuts the continental shelf and slope.

JPT

P. 363＾
Crushing of Calcareous Sands During Drained Shear
Authors: Datta M. , Gulhati S. K. , Rao G. V.
Published: December 2007

Sands are known to crush under stresses at high confinement. Particle crushing is more predominant under shear stresses than under isotropic compression. Stresses in soil under deep foundations often reach the range where crushing becomes significant. Calcareous sands crush more readily than terrigenous quartzitic sands. Calcareous sands occur as skeletal remains of marine organisms and/or as nonskeletal oolites of calcareous material. Skeletal calcareous sand grains are characterized by the presence of intraparticle voids that increase the tendency of these sands to crush under stress. Presence of thin plate-like shell fragments further increases the crushability of calcareous sands.

Deposits of calcareous sands are encountered extensively on the continental shelves lying between latitudes 30°N and 30°S. In many such marine areas, jacket-type offshore structures for oil production are being founded on calcareous sand strata – e.g., in the Arabian Sea offshore India, in the Bass Strait offshore Australia, and in the Persian Gulf offshore Saudi Arabia. The foundations of these structures consist of deep-penetration piles. These piles derive their axial load capacity from the skin friction resistance and the end bearing resistance offered by the soil strata they penetrate. Static pile load tests in calcareous sand strata have exhibited unusually low values of unit skin friction and unit end bearing capacity.1,2 It is believed that particle crushing that occurs during pile driving and static loading is one of the causes for the low pile capacity.2,3 For design of deep-penetration piles in calcareous sand strata, low values of limiting unit skin friction and limiting unit end bearing capacity currently are adopted in comparison to those being used for terrigenous quartzitic sands.3 To arrive at a rational design practice for piles in calcareous sands, one must begin by (1) identifying a method for quantitatively expressing the the sands' propensity to crush, (2) determining the extent of crushing of different types of calcareous sands in comparison to terrigenous sands, and (3) isolating the influence of crushing on shear behavior, which partly controls the end bearing and skin friction offered by such sands.

This paper describes the results of an experimental investigation designed to achieve these three objectives and, in part, offers an explanation for the low skin friction and end bearing values in field tests.
Beyond Heat Checking: Frictional Heating Causes Drillpipe Failure in an Extended-Reach Well
Authors: Vernon R. J. , Wade E. H. R.
Published: December 2007

Failure of a 5-in. proprietary hole-cleaning drillpipe joint occurred during platform drilling of a North Sea extended-reach well. The joint was run in heavyweight drillpipe above the bottomhole assembly (BHA). Its failure resulted in the loss of the BHA, including high-value rotary-steerable tools, at 23,250 ft measured depth (MD). The failure occurred when the string was being rotated out through a tight spot. Topdrive stallouts and intermittent circulation were experienced. The maximum overpull applied was 50,000 lbf. The appearance of the recovered pipe indicated ductile failure, despite a zone of abnormally high hardness adjacent to the fracture.

Investigation established that local frictional heating had heated the drillpipe above 1,441°F and that ductile failure had occurred when hot, although the string had not been overloaded in tension or torsion. After the rupture, the mud-flow quench hardened the hot pipe to above 572 Vickers of 10kg load Hardness (HV10) [approximately 54 Rockwell Hardness on a C scale (HRC)—Note: hardness values are given "as measured"; conversions are approximate and for information only].

"Heat checking" (i.e., downhole surface hardening of frictionally heated drillpipe) is an established phenomenon that is described in the literature. The case reported herein represents an extreme consequence of frictional heating that has important implications for the management of topdrive drilling operations.
Three-Phase Hydraulic Conductances in Angular Capillaries
Authors: Al-Futaisi Ahmed , Patzek Tad W.
Published: December 2007

In this paper, we extend to three fluid phases a prior finite-element study of hydraulic conductance of two-phase creeping flow in angular capillaries. Previously, we obtained analytic expressions for the hydraulic conductance of water in corner filaments. Here, we present the results of a large numerical study with a highresolution finite-element method that solves the three-phase creeping flow approximation of the Navier-Stokes equation. Using the projection-pursuit regression approach, we provide simple analytic expressions for the hydraulic conductance of an intermediate layer of oil sandwiched between water in the corners of the capillary and gas in the center. Our correlations are derived for the oil layers bounded by the concave or convex interfaces that are rigid or allow perfect slip. Therefore, our correlations are applicable to drainage, spontaneous imbibition, and forced imbibition with maximum feasible hysteresis of each contact angle, oil/water (O/W), and gas/oil (G/O). These correlations should be useful in pore-network calculations of three-phase relative permeabilities of spreading oils. Finally, we compare our results with the existing correlations by Zhou et al.18 and Hui and Blunt,19 who assumed thin-film flow with an effective film thickness proportional to the ratio of the flow area to the length of the no-flow boundary. On average, our correlations are two to four times closer to the numerical results than the corresponding correlations by Zhou et al. and Hui and Blunt.
Severe Slugging Attenuation for Deepwater Multiphase Pipeline and Riser Systems
Authors: Tengesdal J. Ø. , Sarica Cem , Thompson Leslie
Published: December 2007

Exploitation of offshore petroleum reservoirs has recently moved to ever-increasing water depths. Production from fields in water deeper than 1800 m is now a reality. The use of long deepwater risers that conduct production from multiple wellheads on the sea-floor to the surface predisposes the system to severe slugging in the riser for a wide range of flow rates and seabed topography. When one considers the length of the deepwater risers, the problem is expected to be more severe than in production systems installed in shallower waters. Severe slugging could occur at high pressure, with the magnitude of the pressure fluctuations so large as to cause a shorter natural flow period with subsequent consequences, such as premature field abandonment, loss of recoverable reserves, and earlier-than-planned deployment of boosting devices.

In this study, a novel idea to lessen or eliminate severe slugging in pipeline/riser systems has been thoroughly investigated. This idea was first proposed by Barbuto1 and later developed independently by Sarica and Tengesdal.2 The principle of the technique is to transfer pipeline gas to the riser at a point above the riser base. The transfer process will reduce both the hydrostatic head in the riser and the pressure in the pipeline, consequently lessening or eliminating severe slugging by maintaining steady-state two-phase flow in the riser.

An experimental study has been conducted with a 7.62-cminside-diameter (ID) riser (14.63 m high) and pipeline (19.81 m long) system. A broad range of data was collected from the facility in both the severe slugging and stable regions. It was found that the severe slugging models currently available do not predict the region accurately for larger-diameter pipes. Data acquired with the external gas bypass have proved the proposed elimination technique.
Gas-Phase Viscosity of Hydrocarbon Mixtures
Authors: Lee A.L. , Eakin B.E.
Published: December 2007

Atmospheric pressure viscosity values for light hydrocarbons were calculated by a simple mixing rule based on the Sutherland constants for pure components. This method was further extended so that the atmospheric pressure viscosity of a mixture may be calculated based on the molecular weight information only.

Introduction

A proven method for estimating the gas-phase viscosity of a mixture is the one by Herning and Zipperer. This mixing rule has the following form:

(1)

One method for calculating the pure component viscosity mu is the Sutherland equation, which has the following form:

(2)

The Sutherland constants B and S are determined from experimental data. A set of Sutherland constants for light hydrocarbons based on the data of several investigators is presented in Table 1.

APPLICATION

The Herning-Zipperer equation and the Sutherland equation were used to obtain an equation for calculating the gas-phase viscosity of light hydrocarbons. This equation has the form,

(3)

where,

(4)

and

(5)

Eq. 3 was used successfully in the study of methane-n-butane mixtures. Further analysis indicated that the Sutherland constants are a function of molecular weight. The gas-phase viscosity may be calculated based on molecular weight information only. The following equation was developed:

(6)

The atmospheric pressure viscosity of ethane, propane, n-butaneandfourmethane-propanemixtwes calculated on the basis of Eq. 6 are compared with the data of other investigators in Tables 2, 3, 4 and 5, respectively. A plot of atmospheric pressure viscosity vs molecular weight based on Eq. 6 is presented in Fig. 1.

SPEJ

P. 247ˆ
Reservoir Modeling for Horizontal-Well Exploitation of a Giant Heavy-Oil Field
Authors: Tankersley T. H. , Waite M. W.
Published: December 2007

The Hamaca field, located in Venezuela's Orinoco heavy-oil belt, is a giant extra heavy-oil accumulation operated by Ameriven, an operating agent company for PDVSA, ConocoPhillips, and ChevronTexaco. Over the 35-year life of the field, more than 1,000 horizontal laterals are planned to deliver 190,000 BOPD to a heavy-oil upgrader facility. Reservoir models are built to support a broad continuum of activities to meet this objective. This paper will review the Hamaca reservoir-modeling process, the challenge of integrating many sources of geologic and geophysical constraints (including horizontal-well information), the focus on continuous model improvement, and issues unique to Hamaca rock and fluid properties. We will show that efficiently evolving a very large geocellular model in an active project like Hamaca can be accomplished through the use of object-oriented process automation. In addition, the paper will illustrate that careful consideration should be paid to issues related to horizontal-well sampling bias and positional uncertainty before constraining a geocellular model with horizontal-well data. The paper will discuss the multiple sophisticated modeling techniques that were used to address the objectives of the Hamaca modeling program.
Development of the Alba Field-Evolution of Completion Practices, Part 1: Openhole Screen-Only Completions to Gravel Pack
Authors: Murray G. , Brookley J. , Ali S. , Davidson E. , McMillan N. , Roberts J.
Published: December 2007

The Alba reservoir (located in the central North Sea) is a highly permeable, unconsolidated sand body with lenses of reactive shales within the reservoir sand. From the initial decision to exploit the field with horizontal wells, there has been an evolutionary approach to selecting the most appropriate drilling fluid and completion technique. Field development has been marked by a drive to increase productivity and reduce the total cost of the ownership of the asset.

The major challenges in completing wells in this field involve sand control and inhibition of reactive reservoir shales.

Initially, completions were prepacked screens in open hole, and the fluid used to drill the reservoir section was oil-based mud (OBM). Productivity was lower than expected, but improvements were achieved by switching to sized salt water-based mud (WBM) and initiating a very stringent quality-control procedure for the drilling and completion fluids. However, screen failure occurred within 2 to 3 years of production startup, and the wells almost invariably sanded up. More recent changes have involved a switch to sized calcium carbonate WBM and openhole gravel packs.

Because the geology of the Alba field dictates that there is almost always some shale exposed in the openhole reservoir section, it was found that the gravel-carrier fluid needs to be equally as inhibitive as the drill-in fluid.

Since 1998, 13 openhole gravel packs have been successfully completed, with high flow rates and no history of sand production in all cases.

This paper deals with the performance of the various techiques applied and details the best practices derived for optimum productivity and screen longevity.
The Mathematical Model of Nonequilibrium Effects in Water-Oil Displacement
Authors: Barenblatt G. I. , Patzek T. W. , Silin D. B.
Published: December 2007

Forced oil-water displacement and spontaneous countercurrent imbibition are the crucial mechanisms of secondary oil recovery. Classical mathematical models of both these unsteady flows are based on the fundamental assumption of local phase equilibrium. Thus, the water and oil flows are assumed to be locally distributed over their flow paths similarly to steady flows. This assumption allows one to further assume that the relative phase permeabilities and the capillary pressure are universal functions of the local water saturation, which can be obtained from steady-state flow experiments. The last assumption leads to a mathematical model consisting of a closed system of equations for fluid flow properties (velocity, pressure) and water saturation. This model is currently used as a basis for numerical predictions of water-oil displacement.

However, at the water front in the water-oil displacement, as well as in capillary imbibition, the characteristic times of both processes are, in general, comparable with the times of redistribution of flow paths between oil and water. Therefore, the nonequilibrium effects should be taken into account. We present here a refined and extended mathematical model for the nonequilibrium two-phase (e.g., water-oil) flows. The basic problem formulation, as well as the more specific equations, are given, and the results of comparison with an experiment are presented and discussed.
Smackover Nacatoch Crude Oil – Separation of Surfactant Precursors and Their Effect on the Crude
Authors: Runnels J. H. , Engel C. J.
Published: December 2007

A procedure is given for separating surfactant precursors that occur in some crude oils. The effect of the precursors on the properties of the oils are described also. The separations were made by silica gel chromatography on crude oil from which the asphaltenes had been removed. The effect of the precursors on the properties of the crude was evaluated by blending the surfactant precursors into the original oil, a modified oil, or a hydrocarbon solvent such as benzene.

Precursors activated and converted to surface active materials by a strong base such as sodium hydroxide are effective in reducing the interfacial tension between the oil and aqueous phase. Occurrence of precursors in crude oils is essential for improved oil recovery by the causticflood process. The procedure for separating the precursors should provide a viable means for evaluating the applicability of a causticflood tertiary oil recovery process to a particular crude or reservoir.
History Matching of Three-Phase Flow Production Data
Authors: Li Ruijian , Reynolds A. C. , Oliver D. S.
Published: December 2007

Adjoint equations for 3D, three-phase flow problems are developed and implemented to calculate the sensitivity of production data to permeability fields and well skin factors. Typically, the development of adjoint equations is rather tedious, but the formulation given here makes the development and numerical solution of adjoint equations straightforward. The procedure for calculating sensitivity coefficients is coupled with a fully implicit finite-difference simulator to develop an automatic history-matching procedure. Even if one does not wish to fully automate history matching, sensitivity coefficients are useful for understanding the physics that control 3D multiphase flow and the influence of local reservoir properties on production data. Procedures to estimate the value of particular types of data [pressure, producing gas/oil ratio (GOR), and water/oil ratio (WOR)] for reducing the uncertainty in estimates of reservoir properties are applied and discussed.
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. For example, a large-scale field case was simulated using the coupled model with 16 processors for the geomechanics model. The total CPU time for a 30-year simulation run was approximately 2 hours. These results indicate that it is both economical and practical to use the proposed procedure and parallel computing for analyzing field-scale problems that integrate reservoir and geomechanics simulation.
Wettability, Saturation, and Viscosity From NMR Measurements
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.