bluuebunny/crossref_metadata_2025 huggingface dataset:
The Dye-Photo Tool: Its Operation and Applications
Authors: Bryant C.M.
Published: December 2007

Description of Tool

The need for an economical, practical method for accurately locating zones of water entry in a wellbore has long been recognized by production men. The development of waterflooding made necessary a means of determining which horizons were being flooded, and the rate of flooding of each zone during actual operations. Research resulted in the Dye-Photo tool shown in Fig. 1.

The tool is designed to measure the translucency of any liquid in which it may be suspended. As fluid passes between a light source and a photo-electric cell. its light transmissive properties are measured. This data is transmitted to the surface where it is recorded (Fig. 2). By conditioning the fluid in the wellbore with an opaque dye, any fluid migration or dilution can be detected readily.

The Dye-Photo tool has three major components:a bailer for containing and releasing the dye,a photo-electric cell which accurately measures any change in light intensity in the conditioned section, anda sonic collar locator for coordinating depth measurements.

The tool is operated by electrical impulses transmitted from the surface through the standard 5/16-in. diameter single-conductor electrical armored cable.

The consolidation of these three components into single tool has greatly reduced the time, and resulting expense, required for conducting a survey. Simplicity of operations and easily interpreted results are characteristics of surveying with the Dye-Photo tool. Accuracy of results has been attested by the success of subsequent remedial operations.

Preparing for Survey

Certain fundamental preparations should be made for conducting a water location survey using the Dye-Photo tool:Water must be standing in the wellbore, at lease throughout the section to be surveyed.If water has been injected into the formation recently, the well should be produced in sufficient quantity to eliminate the possibility of injected water being produced during the survey from a normally non-producing zone.The well should be cleaned out to total depth. All cavings should be bailed or sand-pumped.For a pumping well with tubing and rods pulled, some method of producing the well (usually either a bailer or swab) must be available.If the well is to be surveyed down the annulus, a special wellhead should be installed to minimize the hazards of running a line down the annulus. The clearance between tubing couplings and casing must be sufficient to allow the free passage of the tool.Flowing wells should be equipped with open-ended tubing, suspended above the zone to be surveyed. (The Dye-Photo tool will pass through a standard 1-25/32-in. seating nipple).If a well containing a packer is to be surveyed down tubing, the opening through the packer must be sufficiently large to allow passage of the tool.A mast of some description must be available to handle the "derrick" sheave.
The Effect of Slant Hole, Drainhole, and Lateral Hole Drilling on Well Productivity
Authors: Roemershauser Alvin E. , Hawkins Murray F.
Published: December 2007

Introduction

Methods have been developed for drilling (a) slant holes and (b) one or more curved holes from a common central hole in producing formations. These wells will have productivities exceeding that of a single hole drilled normal to and fully penetrating the producing stratum. other factors being equal. This increase is due to the decrease in resistance to flow in the vicinity of the wellbore by an increase in the cross section exposed to flow with increasing footage drilled in the formation and due to the geometrical arrangement of the holes with respect to the drainage radius or boundary. Where other factors are not equal, for example, where zonal damage exists in the single, fully penetrating hole but not in the slant or curved holes, additional increases in productivity will accrue.

Many of these wells have been drilled in the past and are currently being drilled with various results reported. While the authors are aware of some of the practical aspects of drilling and completing these multiple. curved holes, it is their hope to provide some basic data on the improvement in productivity to be anticipated in these wells for a number of hole arrangements or patterns.

Model Studies

Electric analogue or model studies have been used for solving some reservoir fluid flow problems in which the mathematical solutions are unknown, too approximate or too complex. For example, recent studies have used this method to determine the effect of shot density, diameter, and depth of penetration of gun perforations on well productivity. The success of these studies depends upon the analogy between Ohm's Law for electrical flow and Darcy's Law for incompressible fluid flow in homogeneous rock. Where a geometrical scale reduction is desired, a single scale factor is applied to all dimensions.
A Correlating Device for Predicting Reservoir Performance
Authors: Heuer George J. , Power Harry H.
Published: December 2007

The paper develops a means for predicting the relative permeability of gas to oil for a reservoir on the basis of early production data. The method is based on the observation that a log-log plot of the cumulative gas versus the cumulative oil production frequently results in a straight line, particularly in the case of solution-gas drive reservoirs, or reservoirs with a partial or delayed water drive.

The method of calculating the relative permeability of gas to oil from this relationship is discussed, together with the specific application to the actual behavior of the Schuler Jones sand pool, Union County, Ark.

Introduction

Ultimately, the determination of accurate relative permeability values may be solved, partially or completely, in the laboratory. At present the difficulty in obtaining representative core samples, the proper weighting of relative permeability values and the inadequacies existing in reservoir equations make it desirable to find some way for the determination of the ratio kg/ko which, when substituted in existing equations, will permit the prediction of future reservoir performance.

The experimental values of relative permeability as determined in the laboratory do not coincide closely with values calculated from field production data. This difference, probably, is a reflection of the original fluid distribution as well as that resulting from dynamic conditions of flow, which result in non-uniform saturation-permeability relationships from one portion of the reservoir to another. The calculated relative permeability for the field is a weighted average value, representing all the instantaneous variations in permeability alone flow lines into the well-bore due to differences in absolute permeability, saturation, pressure and pressure gradient.

At present, it is virtually impossible to simulate these conditions in the laboratory. This paper was written in an attempt to determine the relative permeability of the gas to oil phases from the relationship between oil and gas cumulative production. A prior method for determining field relative permeability by means of the "conformance factor" has been described by Patton.
Inertial and Slip Effects in Steady-State Radial Gas Flow Through Porous Media
Authors: Dranchuk P.M. , Piplapure A.R.
Published: December 2007

Steady horizontal radial gas flow through porous media may be described by means of the equation(1)

provided there is no slip at the gas/solid interface and provided there is no slip at the gas/solid interface and q is taken to be positive in the r direction. If one assumes that the modified gas law holds and that viscosity, compressibility, and temperature remain constant, this equation may be integrated to yield(2)

which is similar in form to that proposed by Tek et al. This equation may of course be reduced to the well known form employed for Darcy flow by deleting the second term on the right-hand side. However, it has been shown that neither slip nor inertial effects should be neglected when linear laboratory gas flow tests are used to evaluate rock properties. It has been observed that the same is true for laboratory data when taken in radial tests. Although Eq. 1, modified to allow for slip, may be integrated for linear flow, radial flow yields a nonlinear ordinary differential equation with no known solution. However, an approximate solution may be developed in the following manner: To allow for slip, Eq. 1 may be modified and written as(3)

where(4)

If the modified gas law applies and viscosity, compressibility, and temperature are assumed to remain constant at their average values, Eq. 2 may be converted to the form(5)

Substitution of Eq. 4 into Eq. 5 yields(6)

If one defines(7)

and(8)

Eq. 6 may be written as(9)

or(10)

As was stated earlier there is no known solution to this nonlinear ordinary differential equation. Although this equation may be attacked with numerical techniques to estimate rock properties using flow data, the procedure is involved and difficult. However, if the ratio b/p is sufficiently small, Eq. 9 may be approximated by deleting the term (1 + b/p) in the numerator, in which case(11)

or(12)

This equation may be integrated between the limits

; and;

to yield

(13) or(14)

P. 1155
The Shale-Compensated Chlorine Log
Authors: McKinlay P.F. , Tanner H.L.
Published: December 2007

Although many chlorine logging systems have been used by the petroleum industry, they never attained widespread popularity. The use of many of these systems was limited by their sensitivity to increasing shale content. A shale-compensated chlorine logging system (SCC) has been developed and evaluated. The SCC log interpretation has proven to be correct in predicting the type of fluid behind the casing more than 80 percent of the time.

Introduction

The chlorine log was introduced to the petroleum industry in the late 1950's. The primary purpose of this log was to determine the amount of salt water in the formations immediately behind the production casing and to relate this salinity measurement to hydrocarbon content. Although many chlorine logging systems were used by industry,1–4 they never attained widespread popularity. The use of many of these systems was limited by their sensitivity to increasing shale content.

A shale-compensated chlorine logging system (SCC)5 has been developed and extensively evaluated. The recorded log supplies a continuous salinity profile of the formations behind the casing. A specific advantage of this log over other similar logs is that the system compensates for the effect of shale on the salinity measurement. Also, the porosity, lithologic, and borehole fluid effects on the salinity measurement are minimized.

The log has been run in several hundred cased wells. The majority of the runs have been made in wells subject to workover and/or abandonment. New hydrocarbon-bearing intervals have been identified and oil-water contacts in producing reservoirs have been located. The SCC log interpretation has proven to be correct in predicting the type of fluid behind the casing more than 80 percent of the time. Oil production has been obtained in many wells that, before logging, were considered to have little, if any, economic potential.

The SCC log will give reliable results at logging speeds of 20 to 30 ft/min in formations containing high porosity and salinities above 45,000 ppm NaCl. Slower logging speeds are recommended for areas where porosities are low and/or salinities are less than 45,000 ppm NaCl. The possibility of successful completions based on the log interpretation decreases rapidly when porosities are less than 20 percent and formation salinities are below 30,000 ppm NaCl.

Tool Design

The SCC system was specifically designed to minimize the effects of shaliness, porosity, and lithology on formation salinity measurements and water saturation (Sw) determinations.

The system measures thermal neutron-capture gamma radiation in two gamma ray energy ranges: 1.3 to 2.92 MeV, recorded as the NG (Hydrogen) curve, and all gamma ray energies above 3.43 MeV, recorded as the NG (Chlorine) curve. The detector is a 2-in. by 4-in. long NaI(Tl) scintillation detector that is spaced 15¾in. (center to center) from a 2.3 × 107 neutron / americium - beryllium neutron source. Lead is used as shielding material between neutron source and detector.
Exploration and Production Economics of Low-Permeability Shallow Gas Formations In Appalachia
Authors: Vadgama Usman N. , Hinkle Bill B.
Published: December 2007

Like an old spring that never will become a mighty Mississippi, but that you can count on endlessly for your own needs, many of the gas wells in Appalachia are lean but dependable. They may not be the Big Stuff, but they don't cost an arm and a leg, either.

Introduction

Recently, much has been said and published in the literature on the probable future energy supply and demand structure of the U. S. There is no need to emphasize further the scarcity of future energy supply or criticize regulatory bodies. Forecasts are that by 1990 the natural gas industry must supply more than 46 Tcf annually to meet America's consumer requirements. This is almost three times the current annual gas sales. All possible mean must be activated to meet those demands. One of the possible supplemental sources is an efficient exploitation of the known reservoirs. In an attempt to find new gas reserves in Appalachia, much attention has recently been given to deep drilling to test additional sediments. But there remain in this region huge expanses of shallow gas-bearing formations that are only partly developed. The further development of these sources has been restricted because of increasing drilling and operating costs and depressed gas prices, and the poor cash flows associated with low-deliverability wells. The petroleum industry's urgent need for additional reserves, coupled with recent intrastate price increases, has led many operators in other areas to develop reservoirs that were once considered too tight to provide a reasonable return on investment. Adding these factors, as well as relatively low leasing and rental costs, to the existence of sophisticated completion techniques has made the development of lower-permeability fields profitable. The Appalachian basin is worth an intensive second look. This report is based on 40 years of historical data on drilling costs, pressure buildups, open-flow potentials, and deliverabilities for more than 2,000 wells in eastern Kentucky, West Virginia, and Virginia. It analyzes from an economic point of view the exploration and production performance of shallow gas formations. performance of shallow gas formations. Shallow Gas Formations in the Appalachian Basin

Natural gas in the Appalachian basin is found in a large section from Cambrian to Permian age and covers geographically most of the basin. However, the most extensive fields are in Pennsylvania, West Virginia, and Kentucky and the greatest production has come from there. It is not our intention to go into detail on the geology of the area. Neither do we propose to cover the production performance of the propose to cover the production performance of the entire Appalachian basin. Our observations are limited to the shallow gas formations found mainly in eastern Kentucky, West Virginia, and Virginia. The analysis is based on data from the leases operated by Ashland Oil, Inc.

JPT

P. 985
In-Situ Acid Neutralization System Solves Facility Upset Problems
Authors: Greene E.B. , Lybarger J.H. , Richardson E.A.
Published: December 2007

Introduction

Much of the world's crude oil is produced as emulsions that must be treated (demulsified) to be marketed. Normally, these emulsions can be readily broken by the addition of small amounts of demulsification chemicals, retention time, and, if necessary, heat. However, the oil produced from wells after an acid stimulation can be extremely difficult to treat, even with heat and large additions of treating chemicals. Poor demulsification can result in curtailed production, wet oil at the sales point, and large amounts of oil in the effluent water.There appear to be three basic reasons why emulsions from acid returns are more difficult to treat than normal production.1. Crude oils often contain organic acids and bases. Neutralization of these acids and bases can result in surface-active compounds that will lower the oil/water interfacial tension. With a lower oil/ water interfacial tension, the stable size of the dispersed droplet in the emulsion is much finer at any fixed agitation and thus more difficult than normal to demulsify. Fig. 1 shows the lowering of the oil/ water interfacial tension for an East Bay, La., crude in both the acid and the base.2. Acid media tend to result in adsorbed organic films at the oil/water interface. These films (generally asphaltenes and resins) act as physical barriers to the coalescence of the dispersed droplets. The strength of the films is increased at lower pH's.3. Acid can alter the wettability of loosened formation fines so that the new oil-wetted solids stabilize the emulsion. Like film strength, the apparent oil wetting is increased at lower pH's.We have developed a method to avoid these emulsion upset problems by controlling the pH of the return fluids.

Acid Spending System and Design

A technique has been developed to neutralize acid in situ. The system, designed to avoid both pH extremes of the returning acid treatments, consists of adding the diamide urea and an amide, such as acetamide or dimethyl formamide, to the acid.

JPT

P. 1153
Some Sidelights in Petroleum's Economic Progress
Authors: Willson C.O.
Published: December 2007

This discussion concerns what might be considered the by-product developments and trends, or parts of the whole, within the oil industry which come to the attention of an editor in connection with his daily and weekly tasks.

Future Demands

Predicting yearly petroleum demands has become a somewhat hazardous undertaking in this country since World War II. In some years the projections have varied so widely from actual demands as they have materialized that they have lost much of their value as a guide to operators. For example. most of the projections of a year ago called for an increase in 1954 U. S. demands of 4 to 4 1/2 per cent over 1953. The increase was less than 1 per cent. This means that the actual demand was around 250,000 B/D less than the anticipated level of operation, and that fact accounts for some of the unwanted oil developments of the past year.

It is true, however, that the good years tend to offset the poor ones so that the five and 10-year periods work out, as regards demands, more in line with predictions. With this situation in mind some economists are predicting more than average gains for 1955. Keeping in mind that in these days of surpluses it is easier and less painful to expand operations than it is to contract them, a gain of 5% per cent domestic appears reasonable at this time. With a further decrease in exports in prospect we end Lip with a 4.8 per cent gain in over-all demands.

This will total an estimated 8,483,560 B/D in this country for this year or a gain of 388,560 B/D over the year that has just closed. Of this total gain of 141,824,400 bbl for the entire year it is estimated that 78 per cent will come from domestic crude oil producers, 12 1/2 per cent from imports. and 8 1/2 per cent from natural gas liquids.
Analysis Procedure for Variable-Rate Pressure Drawdown Data
Authors: Lee W.J. , Harrell R.R. , McCain W.D.
Published: December 2007

Use of pressure drawdown tests to characterize gas wells has long been accepted, in principle, to be an excellent formation evaluation technique. In practice, however, the theoretical requirement that flow rates must be maintained strictly constant during the test has led to two major problems:the constant flow rate requirement is frequently ignored, and use of conventional analysis on such tests has led to serious error in many cases, leading to a loss of confidence in drawdown testing; orthe constant flow rate is maintained, but only with a great deal of difficulty.

Winestock and Colpitts showed that both problems could be avoided if gas-well drawdown tests were run with a fixed choke - usually resulting in a slowly decreasing flow rate during the test - if a simple modification of conventional analysis theory is employed. In fact, Winestock and Colpitts claimed that the method they proposed would be adequate in general for smoothly varying flow rates, even though the total change in flow rate from beginning to end of a test was large. This claim requires justification because the method proposed by Winestock and Colpitts is an approximation, and it clearly must fail when the rate of change in flow rate is sufficiently large. The purpose of our investigations, therefore, was to find the limits of applicability of the Winestock and Colpitts method.

First, we reviewed their proposed method and the reason for the method. A frequently used equation describing a pressure drawdown test in a gas well is pressure drawdown test in a gas well is+F (1)

In this equation all terms except flowing bottom-hole pressure, Pwf, and test time, t, are assumed to be constant. Winestock Pwf, and test time, t, are assumed to be constant. Winestock and Colpitts point out that use of the equation in this form can lead to serious errors if it is applied to analyze drawdown tests in which flow rates vary even slightly during the test. They propose, however, that for a test with flow rate varying slightly, the test is modeled adequately by a simple rearrangement of Eq. 1:

= 712 (2)

They propose that the entire group on the left side of Eq. 2, consisting of two variables, bottom-hole flowing pressure, Pwf, and gas production rate qr, both measured pressure, Pwf, and gas production rate qr, both measured during the test, be plotted against the logarithm of test time, t. The permeability thickness product would then be a function of the slope of the resulting line. The turbulence constant, F B, must be obtained before this graph can be prepared.

P. 115
The Effect of Asphaltene Precipitation on Carbonate-Rock Permeability: An Experimental and Numerical Approach
Authors: Ali M. A. , Islam M. R.
Published: December 2007

A series of experiments was carried out to determine the effect of asphaltene precipitation on the intrinsic permeability of carbonate rocks. Experiments indicated the existence of three different flow regimes, namely monotonous steady state, quasisteady state, and continuous plugging. The numerical model helped identify mech- anisms involved in these flow regimes. The existence of a contin- uous plugging regime at a high flow rate is of particular concern in the petroleum industry because of increased probability of plugging near the wellbore. The numerical model couples the surface excess theory for adsorption with the mechanical entrapment theory. The mathematical model accurately predicts permeability damage from mechanical trapping and adsorption. The model predictions agree favorably with experimental results for different flow rates.
Developments in Synchrotron X-Ray Microtomography With Applications to Flow in Porous Media
Authors: Coles M. E. , Hazlett R. D. , Muegge E. L. , Jones K. W. , Andrews B. , Dowd B. , Siddons P. , Peskin A. , Spanne P. , Soll W. E.
Published: December 2007

High resolution computed microtomography (CMT) with synchrotron X-ray sources provides the ability to obtain three-dimensional (3D) images of specimens with a spatial resolution on the order of micrometers. Microimaging capabilities at Brookhaven Natl. Laboratory's Natl. Synchrotron Light Source have been enhanced to provide larger and higher resolution 3D renderings of pore networks in reservoir rocks at a fraction of the time required in previous first generation scanning methods. Such data are used to model single and multiphase flow properties in digital images of real porous media. Pore networks are analyzed for tortuosity and connectivity measures, which have been elusive parameters in transport property models. We present examples of porosimetry simulation through network modeling to produce initial water saturation and residual oil distributions in a water-wet pore system. Furthermore, pore networks can provide the boundary condition framework for more rigorous simulations of displacement, such as in the lattice Boltzmann simulated waterflood example provided. Direct comparison between simulation and experiment is also possible. CMT images of a 6-mm subsection of a 1-in. diameter reservoir core sample were obtained before and after flooding to residual oil. The fluid distributions from CMT, lattice Boltzmann waterflood simulation, and percolation-based network modeling were found to be highly correlated. Advances in 3D visualization will allow even greater digestion and interpretation of phenomena dependent upon pore interconnectivity and multipore interactions.
New Well Architectures Increase Gas Recovery and Reduce Drilling Costs
Authors: Horn M. J. , Plathey D. P.
Published: December 2007

Gas recovery on the Bongkot field has increased by 5% and well costs have decreased by 50% over a 4 year period. This was achieved by modifying the production strategy, and evolving well designs from classic multizone completions to tubingless monobore designs. Tubingless well designs have allowed a more aggressive perforating strategy, which taps gas reserves that were previously lost. Reduced consumable requirements and elimination of completion operations have contributed to lower overall well costs. This paper describes the process that led to the development of the tubingless design.
Fracturing, Frac Packing, and Formation Failure Control: Can Screenless Completions Prevent Sand Production?
Authors: Morita Nobuo , Burton R. C. , Davis Eric
Published: December 2007

Some successful results have been reported for screenless frac-packing methods1–3; however, no scientific guidelines were given regarding the conditions under which a screen can be eliminated from a well. In this paper, we report field data from sand-producing wells and review the onset and the rate of sand production for those wells with and without hydraulic fractures. From these field observations and numerical modeling analysis, we give guidelines for when a screen must be run and when a screen can be eliminated.
Practical Application of NMR Logging in Carbonate Reservoirs
Authors: Logan W. D. , Horkowitz J. P. , Laronga Robert , Cromwell D. W.
Published: December 2007

Nuclear magnetic resonance (NMR) data acquisition and interpretation in carbonate reservoirs is much more challenging than in sandstones, where it is a well-established technology. Heterogeneous porosity distribution, a broad range of pore sizes, a wide variety of complex textures, and low surface relaxivity combine to complicate the picture considerably. The successful practical application of NMR in these reservoirs requires the development of acquisition and interpretation techniques specifically suited to the task.

In carbonate reservoirs dominated by intercrystalline or inter-granular porosity, NMR can deliver accurate estimates of porosity, permeability, bound fluid volume, and residual oil saturation (ROS). In heterogeneous carbonate reservoirs more complex interpretation models are required, normally based on the integration of whole core and log data. NMR answer products, based on these new techniques, are presented and validated with core data and by comparison with other logging measurements.
Numerical Study of Natural Convection and Diffusion in Fractured Porous Media
Authors: Ghorayeb Kassem , Firoozabadi Abbas
Published: December 2007

Compositional variation in a rectangular two-dimensional (x,z) fractured porous medium containing a two-component singlephase fluid in the presence of a prescribed linear temperature field is considered. The work examines the effect of the fracture parameters: fracture aperture (or fracture permeability), fracture intensity, and fracture connectivity on the fluid compositional variation. Numerical results reveal that, for a high fracture aperture, a pronounced convective motion within the fractures takes place, whereas the composition is only affected beyond a certain fracture aperture. The effect of connected and discrete fractures on compositional variation is also studied; connected fractures influence the compositional variation much more than discrete fractures, as expected. The convection cells are mainly loops which develop within the connected fractures.
Pressure-History Inversion for Interpretation of Fracture Treatments
Authors: Gulrajani S. N. , Mack M. G. , Elbel J. L.
Published: December 2007

Conventional analysis of hydraulic fracturing treatments with analytical solutions is based on idealized assumptions, which limits its usefulness in many applications. Manual (trial and error) pressure matching techniques by means of a fracture simulator are laborious and consider only one parameter at a time. This paper presents an alternative technique for consistent analysis of pressure records during both injection and decline, including changes caused by rate and fluid viscosity variations. This allows it to be used to analyze calibration as well as propped treatment pressures, which gives it broad field application. The technique includes a formal inversion procedure coupled with a hydraulic fracture simulator that includes both two-dimensional fracture models and a pseudo-three-dimensional height growth model. The algorithm is extended to identify the occurrence of nonuniqueness, an inherent limitation in any fracturing pressure interpretation.

Comprehensive case studies from fracture treatments in different formations in North America, the North Sea, and Africa are presented. Calibration treatments are first analyzed with this technique, then propped treatment pressures are predicted and then confirmed with field measurements. The analysis is applied to both normal and tip-screenout treatments, some with pressure records showing near-wellbore pressure losses. Good agreement between the predicted and measured pressures in these cases shows the validity of the algorithm and confirms its use for field application.
Rheological Properties of Low-Gel-Loading Borate Fracture Gels
Authors: Harris P. C. , Heath S. J.
Published: December 2007

This paper presents a study of hydration, crosslinking, and rheological properties of 15- to 25-lbm/1,000-gal optimized borate-crosslinked guar fluids. Hydration and crosslinking properties of fluids were measured in a new turbulent flow-loop viscometer to simulate the high shear mixing of fracture fluids in surface equipment and the pumping of the fluids down tubulars. Fluids were then heated and measured in laminar flow to simulate fluid flow in a fracture. The effects of conditioning crosslinked fluids in high shear rate flow on laminar flow properties were observed.

Hydration rates were measured for guar at different levels of shear history. Optimum shear levels and times for hydration were observed for the time-dependent base gel fluids. The properties of the crosslinked fluid were critically dependent upon the base gel fluid state of hydration before crosslinking. Properly crosslinked fluids did not shear-thin back to base gel levels but maintained significant viscosity even at high shear levels.

Power-law index values were measured for low-polymer borate fluids with a three-viscometer method that uses constant shear rates. Lower values of n′ were found for the new fluids compared with conventional borate fluids with similar polymer loadings. Proppant transport properties were qualitatively observed in a transparent slot model showing good transport for both an optimized 25-lbm/1,000-gal borate fluid and a conventional 35-lbm/1,000-gal borate fluid.
Development of a Bubble-Population Correlation for Foam-Flow Modeling in Porous Media
Authors: Bertin H. J. , Quintard M. Y. , Castanier L. M.
Published: December 2007

This study shows a bubble-population correlation based on experimental observations and theoretical results obtained at the pore scale (micromodels, network modeling) and at the core scale (transient foam flow in homogeneous media). In this correlation, we express explicitly the evolution of the mobile bubble density (the foam texture that governs foam viscosity) as a function of the physical properties of the porous medium (porosity, permeability, and capillary pressure) and the evolution of the mobile gas saturation. This correlation has been rather easily implemented in a numerical simulator and the resulting set of data has been matched against results of transient experiments performed with unconsolidated porous medium under a computerized tomography (CT) scanner as well as experiments performed in another research institution with natural sandstone. The match of the experimental data and the correlation are good. The results have also been compared with a complete simulation that uses the population-balance model. The agreement is excellent between the two types of models.

This simplified formulation allows decoupling the effect of the porous media parameters, such as porosity, permeability, and capillary pressure, from the effects caused by the surfactant. It conserves most of the benefits of the physics of foam flow as seen in the literature.
Cold Production of Heavy Oil From Horizontal Wells in the Frog Lake Field
Authors: Huang W. S. , Marcum B. E. , Chase M. R. , Yu C. L.
Published: December 2007

Texaco Canada Petroleum Inc. (TCPI) has successfully conducted a 10-horizontal well primary production pilot project at Frog Lake, Alberta, Canada. The gravity of the heavy oil ranges from 10 to 14°API, and the oil viscosity ranges from 20,000 to 50,000 cp. These 10 wells were completed in the Lower Waseca formation (one of five prospective formations in the field) and were produced by use of a coproduction of sand and oil from the reservoir at ambient temperatures, known as cold production. These wells were very successful, with most wells displaying productive capabilities in excess of 100 B/D. Based on the technical success of the 10-well pilot, a long-term staged development plan was established to resolve some technical challenges identified by the 10-well project. These challenges include reduction of operating costs and improvement of artificial lift and well reliability. As part of the development plan, over 70 horizontal wells have been drilled and production has peaked at 3,000 BOPD.

This paper summarizes the history of the Frog Lake field, completion and production techniques for the pilot project, and some of the operational and technical challenges encountered. A field-wide development strategy and potential for enhanced oil recovery (EOR) are also discussed.
Paraffin Deposition From Crude Oils: Comparison of Laboratory Results With Field Data
Authors: Hammami Ahmed , Raines M. A.
Published: December 2007

In this study, we evaluate the characteristics of four reservoir fluids sampled from two offshore fields in the Gulf of Mexico as well as their propensities towards paraffins deposition due to temperature and/or pressure variations. State-of-the-art techniques, namely a cross polarized microscopy and a laser based solids detection system, have been used to measure the onsets of paraffin crystallization temperatures, also known as wax appearance temperatures (WAT) and/or cloud points. The results are presented, discussed and compared to reported field data. Explanations for the observed differences and/or similarities between laboratory and field WAT are proposed.
Concrete FPSO
Authors: Harris R. J. S. , des De´serts Loic , Kenison R. C. , Snell Richard , Kerr David
Published: December 2007

The paper identifies the advantages, features and applicability of a concrete hull for an FPSO and the issues related to project execution. For those considering the options for other field developments, the paper identifies the conclusions and the work on which these were based. The content of the paper is based on extended studies on the advantages, design features and feasibility of fabrication of this new design of the floating production storage and offloading facility (FPSO) hull. This work formed part of British Petroleum's (BP's) review of options for the development of their Schiehallion field in 375 m water depth West of Shetland, the Atlantic Frontier. The conceptual design of the vessel hull was carried out with the objective of providing the best solution for a concrete FPSO for BP's application. This included consideration of capital cost, system availability, operating costs, HSE aspects, decommissioning and disposal. The flexibility ofthe concept, e.g., for addition and modification during service, were also examined. The design process was taken to the stage where these matters had been examined and the design has approval in principal for certi- fication. During the design process the mathematical modeling of vessel motions and mooring forces were confirmed in tank tests. BP participated in the proof of concept, retaining the concept on their final short list of two options for the field development. It was concluded by all parties that this new concept had been fully examined and proved technically.
New Perforation Pressure-Loss Correlations for Limited-Entry Fracturing Treatments
Authors: El-Rabba A. M. , Shah S. N. , Lord D. L.
Published: December 2007

Estimating the perforation pressure loss is an essential part in the design and analysis of hydraulic fracturing treatments. Accurate determination of perforation pressure loss for the rheologically complex fracturing fluids being used today can best be achieved through experimental study. Investigation of the perforation pressure loss for linear polymer solutions, crosslinked gels, and fracturing slurries has been conducted at the Fracturing Fluid Characterization Facility since 1994. Using the data acquired from these experiments, new correlations are developed to estimate the coef- ficient of discharge used in the orifice equation that governs the perforation pressure loss. The correlations can be used to accurately predict the coefficient of discharge for linear polymer solutions and titanium/borate-crosslinked gels. In addition, the slurry correlation can be utilized to determine the dynamic change in the coefficient of discharge for fracturing slurries due to erosion. The presented correlations are developed such that they can easily be incorporated into current fracturing simulators.
Impact of Fluid Selection on High-Permeability Fracturing
Authors: Aggour T. M. , Economides M. J.
Published: December 2007

High permeability fracturing has become a major well completion technique both for production rate increase and, especially, for pressure drawdown decrease. Today, this type of treatment is the main means of sand control in some petroleum regions. Several of these treatments which are characterized by short lengths and, often, disproportionate widths, have been reported to exhibit positive post-treatment skin effects. This can only be the result of fracture face damage. This paper indicates that if the extent of fracturing fluid invasion is minimized, the degree of damage (i.e., permeability impairment due to filter cake or polymer invasion) is of secondary importance. Thus, if the fluid leak-off penetration is small, even severe permeability impairments can be tolerated without exhibiting positive skin effects. While the first priority in designing fracture treatments should be to maximize the fracture conductivity, it is recommended that in high permeability fracturing, high polymer concentration cross-linked fracturing fluids with fluid loss additives and breakers should be used. Experimental work corroborates these contentions.
Influence of Effective Stress on the Acoustic Velocity and Log-Derived Porosity
Authors: Khaksar Abbas , Griffiths C. M.
Published: December 2007

Experimental studies indicate that when effective stress increases, compressional wave velocity in porous rocks increases. Reservoir pressure reduction, resulting from hydrocarbon production, increases effective stress. For a rock with a given porosity the sonic log may show decreasing values as the pressure in the reservoir decreases. This in turn may lead to underestimation of the actual porosity of the reservoir rocks in low pressure reservoirs. The range of such underestimation for liquid saturated reservoirs may not be significant, but since the influence of effective stress on velocity increases as fluid saturation changes to gas, porosity underestimation by conventional velocity-porosity transforms for gas bearing rocks may increase. Examples are taken from partially depleted gas reservoirs in the Cooper basin, South Australia. The stress dependent nature of velocity requires that the in situ pressure condition should be considered when the sonic log is used to determine the porosity of gas producing reservoir rocks.
Stress Concentration in Tubular Joints
Authors: Potvin A.B. , Kuang J.G. , Leick R.D. , Kahlich J.L.
Published: December 2007

Fatigue cracking caused by stress concentrations in tubular joints has been observed in some fixed platforms installed in hostile environments. platforms installed in hostile environments. Consequently, the ability to assess the magnitude of the stress concentration is a Prerequisite to dealing with the fatigue problem of tubular joints. This paper deals with the problem of computing the stress concentration in three types of simple, nonreinforced joints: T-joints, K-joints, and TK-joints. Semi-empirical equations are presented for estimating the stress concentration due to axial loads and bending moments.

Introduction

In off shore structures stress concentrations usually occur at the intersections of tubular members (i.e., tubular joints). For some joints, the stress concentration can produce a maximum stress at the intersection as high as 20 times the nominal stress acting in the members. Stress concentrations have aggravated the fatigue of tubular joints in many existing offshore structures. Therefore, an accurate computation of stress concentrations is of utmost importance in a tubular joint design.

The first part of this paper presents a discussion of the finite-element analysis method and the associated computer program developed exclusively for the analysis of tubular joints. The second part of this paper describes the parameter study carried out by means of the computer program. Formulas for estimating stress-concentration factors for simple joints commonly used in offshore structures are derived from the results of the parameter study. The usage of the resulting formulas is illustrated by a numerical example.

ANALYTICAL TECHNIQUE

In offshore structures such as fixed platforms and semisubmersible drilling vessels, tubular members comprise the main load-carrying components. Examples of cracking and even complete separation at the intersections of such members have been cited previously throughout the literature. A typical example of such an intersection is shown in Fig. 1. The member of greatest diameter will be referred to as the chord. The smaller diameter members framing into the chord will be called branches. The sections of the chord wall lying within the branch intersection line (if present) will be called plugs. Fig. 2 shows the various simple joint types referred to in this paper.

Because of the relative complexity of the geometrical configuration of tubular intersections as well as the thin-shell theory governing their behavior, reliable prediction of the stresses in such joints by analytical techniques has proven to be costly as well as difficult. Early attempts at analysis ranged from elementary strength-of-materials approaches such as the "punching shear" method to more complicated treatments that solve the governing equations by means of Fourier Series superposition.

SPEJ

P. 287
Mechanical Properties of Friable Sands From Conventional Log Data (includes associated papers 6426 and 6427 )
Authors: Stein N.
Published: December 2007

A new log interpretation method is presented for determining mechanical properties of friable sands. Factors considered in the method include overburden weight, fluid pressure, and additional earth loads caused by local geological conditions. Log data needed for the interpretation include conventional sonic, density, induction, and open-hole gamma ray.

Introduction

Certain in-situ mechanical properties of friable sands must be measured to determine if such formations will remain stable under different wellbore conditions. Stability problems that can then be resolved include estimating (1) how fast oil or gas may be produced without casing a sand problem,1,2 (2) if there is sufficient cementation between adjoining sand grains to avoid a possible sand problem when water production occurs,1,3 and (3) the formation fracture pressure gradient.4 Specific mechanical properties that enable such estimates are sand strength, strength of cementation between grains, bulk compressibility, and Poisson's ratio. This paper presents techniques for calculating these properties.

The means for determining the in-situ mechanical properties of friable sands is through the use of well-log data. The accuracy of these properties determined from log data should be better than the properties determined from log data should be better than the properties determined by direct strength tests with core samples. Weakly cemented materials probably would disaggregate during the core recovery operation, and no strength of cementation would be detected in direct strength measurements. Relief of overburden load results in core expansion and subsequent breaking of weak bonds.

Logs used include conventional sonic, density, induction, and open-hole gamma ray. The conventional sonic log is used in preference to a full-wave sonic log for calculating the mechanical properties of friable sands. The full-wave log can provide both compression and shear-wave travel times if the formation grains do not slip by each other as the acoustic signals pass through. Many of the rock properties could then be calculated directly5,6 from such measurements. Grain slippage apparently occurs readily in many friable sands; the shear-wave signal is dampened severely, and it is difficult to record reliable data. Techniques are developed in this paper that make it possible to substitute conventional sonic-log data for full-wave log data for calculating the mechanical properties of friable sands.

Other methods have been reported1,4,7 for using log data to measure the mechanical properties incorporated all the following factors that can affect the mechanical properties:overburden weight gradients at different depths,other earth loads caused by local geological conditions,cementation,fluid saturation,fluid pressure,different bulk compressibilities, andthe change in elastic modulus values 1 of friable sands at different load conditions. These factors are considered in the calculation technique reported here.
Buckling Analysis in Deviated Wells: A Practical Method
Authors: Mitchell R. F.
Published: December 2007

Current helical buckling models are valid for vertical wells, but provide only approximate solutions for horizontal wells. Solutions of the nonlinear buckling equations for arbitrary well deviation have been developed, but are too complex for practical use. This paper presents a set of correlations that match the exact solutions extremely well, but are simple to use. These correlations show the effects of well deviation on buckling shape, tubing length change, contact force and bending stress.
Silicate Based Muds: Chemical Optimization Based on Field Experience
Authors: Ward I. , Chapman J. W. , Williamson R.
Published: December 2007

Since the reintroduction of silicate fluids into the North Sea in 1994 over 45 hole sections have been drilled using these fluids. The performance of the fluid during the early field trials is discussed together with the compositional changes made as the envelope of performance was extended. The current state of the art in sodium silicate and mixed silicate formulations is presented together with field data to illustrate drilling performance.