bluuebunny/crossref_metadata_2025 huggingface dataset:
Evaluating Completion Damage in High-Rate, Gravel-Packed Wells
Authors: Burton R. C. , MacKinlay W. M. , Hodge R. M. , Landrum W. R.
Published: December 2007

Conoco recently completed and tested a series of high-rate, gravel-packed oil wells. Analysis of the well test data for the first completion indicated that significant formation/completion damage had been caused during the gravel-packing process. Extensive laboratory testing designed to closely simulate the completion procedure was performed in conjunction with detailed completion pressure loss evaluation. The studies identified the loss control material (LCM) pill used during completion operations as the primary source of damage. A new, self-breaking, LCM composition was designed that provided fluid-loss control with minimum formation/completion damage. This LCM system and a number of other design improvements were used in the field's remaining gravel-packed completions.

We describe the analysis of well test data and the application of this information to evaluate completion procedures for these high-rate, cased-hole, gravel-packed completions. The analytical technique used is unique in that it combines laboratory, analytical, and operational data to quantify individual components of the total measured pressure drop across the completion. This approach provides significantly better insight into completion performance than merely stating an overall completion pressure drop, skin value, or well flow efficiency.

The result of this systematic analysis of pressure losses is a better understanding of formation damage effects and the factors that influence them during the completion process. This in turn allows completion procedures to be modified to target specific areas for improvement.
Experimental Investigation on the Injectivity of Phenol-Formaldehyde/Polymer Gels
Authors: Bryant S. L. , Borghi G. P. , Bartosek Martin , Lockhart T. P.
Published: December 2007

Knowing the injectivity of a gelant (i.e., the pressure gradient required to achieve a given flow rate) enables the designer to program the rate/volume schedule of a water shutoff treatment. Bulk gelation times determined from bottle testing have been used often to estimate available pumping time, but such tests do not measure the evolution of gelant rheology as crosslinking proceeds, nor do they measure the tendency of the gelant to undergo filtration within a porous medium. These factors can affect injectivity significantly, resulting in pumping times much less than the bulk gelation time. We describe techniques for discriminating between viscosification and filtration by means of experiments in porous media, making use of multiple pore volume (PV) injection, step changes in flow rates, and in-line capillaries. Tests with phenol-formaldehyde-crosslinked polymer gelants, which possess a number of characteristics favorable to high temperature applications, show that filtration of pregel aggregates in sandpacks and cores can play the dominant role in reducing the mobility of the gelant. The filtration behavior is not universal; one gelant formulation showed no loss of mobility at all by this mechanism. When filtration does occur, it is strongly correlated to the age of the gelant (i.e., time the gelant has spent at temperature) but is relatively insensitive to the permeability of the porous medium or the presence of residual oil. The viscosity of the gelants tested evolves in similar ways in bulk and during flow in porous media.
The Effect of Stress on Permeability of Sandstone Cores
Authors: Gray Donald H. , Fatt Irving
Published: December 2007

Introduction

The effects of mechanical stress on reservoir rock parameters are now generally accepted as beingimportantinreservoirengineeringcalculations. In several oil fields the unique behavior of the reservoir has been attributed to the influence of overburden pressure or internal fluid pressure on rock permeability or fluid content.Although the gross effects of overburden pressure on permeability, porosity, waterflood efficiency, electrical resistance and sonic velocity have now been established, there are some very interesting, and perhaps important, details of rock behavior under stress that have not heretofore been studied.In this paper we will show that permeability anistropy of several sandstones is a function of overburden pressure. We will also show that permeability reduction of cylindrical samples of two sandstones, when subjected to mechanical stress, is a function of the ratio of radial to axial stress.Most studies of overburden pressure effects made in the past have attempted to duplicate reservoir conditions by applying hydrostatic external pressure on all surfaces of the sample. Assuming perfect elasticity, that is, no viscoelastic flow during geological time, reservoir rock in situ cannot be under hydrostatic stress as is apparent from the value of 0.25 for Poisson's ratio for most rock. In the absence of tectonic forces the horizontal stress component

(1)

(2)

If there are directional permeability effects, as has been reported from field and laboratory studies, 10, 11 then one would expect hydrostatic stress as used in the laboratory to give a different permeability reduction from that occurring under reservoir stress conditions.The influence of stress on directional permeability was measured by a modification of the method first described by Maasland and Kirkham for use on soil samples. Their method permits calculation of the permeabilities along each of the three mutually perpendicular axes of a cubic sample. The modification reported in this paper extends the method to observing these permeabilities when the sample is under hydrostatic stress.The Hassler sleeve type of core holder is satisfactory for studying overburden pressure effects on permeability if a known force is applied to the end plugs. Wyble used a sleeve core holder but did not load the end plugs. In this paper we combine sleeve pressure and axial force to give permeability changes which we believe are close to those occurring in reservoirs when reservoir pressure changes. The combination of sleeve pressure and axial force assumes, however, that the sleeve pressure simulates both vertical stress and horizontal stress in one conditions.

METHOD

PERMEABILITY ANISOTROPY

The Maasland and Kirkham method of measuring permeabiHtyanisocopyusesacubeofporousmaterial which is open on three faces and has discs with a center hole for an air inlet cemented to the other three mutually perpendicular faces (Fig. 1).

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P. 95^
Interference Analysis for Anisotropic Formations - A Case History (includes associated paper 6406 )
Authors: Ramey H.J.
Published: December 2007

Many formations, such as channel sand, appear to exhibit simple ky-kxanisotropy. Directional permeability has an important effect onplanning fluid-injection oil recovery. The method discussed in thispaper uses data obtained during water injection to determine major andminor permeability axes and the orientation of the unknown permeability matrix.

Introduction

It has long been known that many formations appear toexhibit simple ky-kx anisotropy. This model also may beapplicable for formations containing trending fracturepatterns. Knowledge of directional permeabilityobviously would have an important effect on planningreservoir development, particularly for fluid injectionoperations. A recent study by Papadopulos outlines methods for interference analysis in anisotropic formations. Themethod is used here to analyze a field water-injection testto determine major and minor permeabilities and theorientation of the unknown permeability matrix. The method also may be extended to pressure falloff (orbuildup) interference analysis.

The theory of flow of either fluid or heat through ananisotropic medium is well established. A brief reviewof this information is sufficient here. We consider that awell is produced at a constant volumetric rate in aninfinite, anisotropic medium. The formation has aconstant thickness and porosity, and the total systemeffective compressibility is constant. Collins has presentedperhaps the best-known solution to this problem in thearea of oil production technology. In the mid-1960's, aseries of papers appeared in the groundwater hydrologyliterature dealing with the problem of well testanalysis for anisotropic aquifers. Studies by Hantush, Papadopulos, and Walton are particularly notable. ThePapadopulos study appears to be well-suited for applicationto analysis of oil and gas well test data and serves asthe basis for this study. The purpose of this paper is topresent analysis of actual field data with the Papadopulosmethod in a form readily useable by petroleum engineers.The method is extended to falloff data.

Theory

The Collins solution for the pressure field caused by awell producing from an anisotropic reservoir is correct, but it assumes the directions of the major and minorpermeability axes are known and are aligned with thewell-location coordinate system. In the general well testanalysis situation, the direction of the major permeabilityaxis would be unknown. Fig. 1 shows the known welllocation x-y coordinate system with the unknown permeability axes, X-Y, oriented at some unknown angle 0.The pressure at (x, y, t) caused by a line-source well at theorigin was presented by Papadopulos:

2 h (pi - px, y, t)kxxkyy - kxy ----------------- =141.2 q B

1- Ei .....(1)2

kxx = 1/2{(kxx+kyy) + [(kxx-kyy)2+4kxy2] 1/2}....(2)

kyy = 1/2{(kxx+kyy) − [(kxx-Kyy)2+4kxy2]1/2}.....(3)

kxx − kxx= arctan ......................(4)kxy

JPT

P. 1290^
A Method for Determining the Exponent Value in a Forchheimer-Type Flow Equation
Authors: Phipps S.C. , Khalil John N.
Published: December 2007

This article presents a direct method for determining the exponent in a Forchheimer-type flow equation. Forchheimer proposed the following expression as the "law of flow" in porous media:

P n = au + bu, .................................(1) L

where

p/ L = pressure gradient u = volumetric velocity (flow rate per unit area) a, b = constants for a particular porous media n = velocity exponent

It is well established in oil and ground-water flow that velocities are generally sufficiently low such that Darcy's law is usually valid as the law of flow. That is,

P = cu,........................................(2) L

where c = a constant.

In those cases where Darcy's law is not valid, Muskat states that the empirical flow data can be expressed in all cases by an equation of the form of Eq. 1, with n 2 when flow velocity is sufficiently high to be in the turbulent flow region. Eq. 1 is also applicable when flow is laminar, but kinetic energy losses are large relative to viscous forces.

Although it is not the purpose of this article to discuss the range of validity of either Eqs. 1 or 2, it should be noted that the application of Eq. 1 is appropriate more often than is commonly recognized. Many high-rate Middle Eastern wells, particularly those in fractured reservoirs, are described by Eq. 1, as first reported by Baker. Using Eq. 2 in place of Eq. 1 can result in errors on the order of 50 percent or more in predicting well rates.

It is well documented in the literature that a rate equation based on Eq. 1 also applies to many gas wells. Nevertheless, the use of the empirical Rawlins-Schellhardt backpressure flow equation remains common. Cornelson has recently presented a discussion of the potential error in predicting gas rates and reserves when the Rawlins-Schellhardt equation is used in place of Eq. 1 for the flow equation.

In addition to reservoir flow considerations, well screens, perforations, and other near-wellbore effects generally cause the pressure loss to be proportional to n th power of the flow rate. Investigators in the field of ground-water hydraulics note that n may deviate significantly from 2 and should be determined separately for each well. In such cases, n is usually determined by trial-and-error curve fitting of well-test data. A direct solution for n, as well as the associated flow coefficients, is possible using the following procedure.

Run the well-flow test such that at least three pressure drawdown values are obtained for three rates at equal flow times.

P. 883
Some Aspects of Sand-Oil Fracturing in Long Heterogeneous Sand Sections
Authors: Wilson Lejeune
Published: December 2007

On the northwestern coast of Peru, the International Petroleum Co., Ltd., initiated sand-oil fracturing in late 1953. As of May 31, 1955, 319 jobs had been performed in 61 of the 71 producing pools and in all eight of the producing formations. The wells treated have thick producing sections completed through gun-perforated casing, perforated liners, or combination strings.

In the average treatment 300 bbl of refined oil was used to carry 18,900 lb of Ottawa sand; in most cases, the sand-oil mix was injected down the annular space. About 50 per cent of the jobs were done in wells where a thick series of sands and shales were exposed.

Of the 319 jobs done, 70 per cent (or 271 jobs) were successful; the total additional oil produced of May 31, 1955, was 1,860,633 bbl and at that time additional oil was still being produced at the rate of 5,419 BOPD. Only the six most important producing sands are discussed in the paper. In one of these (Lower Parinas sand) a comparison was made between the results of nitroshooting and sand-oil fracturing. Composite production curves and typical electrical-log sections are shown for each of the six sands. Also a statistical summary of results from all eight formations is presented.

Variables which might have affected the success of treatments were investigated empirically and theoretically, but no satisfactory means of predicting results of sand-oil fracturing was found. It was noted, however, that the beneficial effects were divided into three categories: induced fractures, elimination of well damage, and opening new reservoirs. The general conclusions were that sand-oil fracturing was successful in wells where as much as 75 per cent of the exposed formation was shale, in old, apparently depleted wells, and that opening new reservoirs plus the elimination of well damage were important factors in the successes.
Construction of Models that Simulate Oil Reservoirs
Authors: Wygal R.J.
Published: December 2007

WYGAL, R.J., GULF RESEARCH and DEVELOPMENT CO., PITTSBURGH, PA.

Introduction

Many laboratory studies of porous media are based on experiments using test packs of sand, glass beads and other granular materials. More confidence can be had in the results of such studies if the test packs are known to have uniform properties throughout, to be mechanically stable and to be accurately reproducible. This paper presents a method by which such packs of a variety of shapes and sizes may be constructed using a particle distributor. Some factors which limit the usefulness of unconsolidated packs as a means for simulating reservoir rock are described. A method of overcoming these limitations, which involves artificial cementation of the packs, is presented.

DEVELOPMENT

Particles packed by the tamping or vibrating techniques are usually either non-uniform or mechanically unstable. An invention by Currie and Gregory overcomes these difficulties to some extent. The invention is based on the use of a stream of falling particles impinging on and passing through a distributor matrix of several layers of closely spaced spheres. The particles are well dispersed by numerous collisions with the spheres. They become homogeneously distributed at some distance below the distributor matrix and at that position are collected in the sample container. This apparatus, however, was found to be ineffective when small particles were used since small particles accumulate on the top surfaces of the spheres.

An improved distributor matrix was made, first in the form of a stack of five sieves, and then in the more adaptable form of spaced layers of wire screen. Fig. 1 shows a longitudinal view through a five-layered distributor of eight-mesh wire screen. This device gives excellent results.* Fine particles pass through the distributor with very little hold up. The fine structure of the wire matrix with its many deflecting surfaces ensures good particle distribution. There are no dead areas immediately below the screen as were sometimes observed to occur below a matrix of spheres. Using such a device, 20–30 mesh sands were packed to a porosity of 32.1 per cent at rates varying from 0.17 to 6 lb/min. The lowest porosity achieved by tamping small increments of similar sands into a container was 33 per cent.Motion pictures at 3,000 frames/sec of the surface of a growing pack of 2–3/4 nun glass beads have helped to show the mechanism by which packs of low porosity are obtained. The beads, although packed at the roe of 5 lb/min, were observed to hit the pack surface singly, for the most part, and at well spaced points of impact.

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P. 281^
Northeast Butterly Pool - Case History
Authors: Butler Roy , McCloud S.D. , Marshall Jack
Published: December 2007

In producing the Northeast Butterly Pool crude oil it was necessary to pump sand consolidating agents into the formation, treat with large amounts of emulsion breaker, blend with high gravity crude, heat in the stock tanks as well as the heaters, and blend additionally as the oil entered the pipeline. Steam jets and drains installed in heaters and two trucks equipped with sand buckets, working 24 hours a day, were necessary to separate the produced sand from the oil and remove it from the area. Despite these problems, over 2,500,000 bbl of oil have been produced in less than 10 years from a reservoir covering 185 surface acres.

Introduction

The Northeast Butterly Pool, located in Garvin County, Okla., approximately 3 miles northwest of the town of Davis, is unique in several respects. It is the purpose of this paper to share the knowledge gained in combatting the many adverse conditions present in the pool. The possibility that the solutions arrived at in exploiting this reservoir might aid in the development of future pools, which would otherwise be abandoned as non-commercial, has been an added stimulus in the writing of this case history.

History of Development

The discovery well of the Northeast Butterly Pool, the W. M. Butterly No.1, was completed on Dec. 20, 1945, at a total depth of 4,422 ft and with a plugged back total depth of 4,109 ft. Producing through perforations opposite the Oil Creek sand formation, Ordovician age, the initial potential, pumping, was 240 B/D of 13° API gravity oil, with a bottom bole pressure of 2,500 psia. With one rig in use the field underwent orderly development on 10-acre spacing with five wells drilled in 1946, four in 1947, two in 1948, and one in 1949. Of the 13 wells drilled, one was a dry hole and one was plugged and abandoned during completion due to mechanical difficulties. An offset, 50 ft west of the latter, was drilled as the eleventh producing well in the pool.
Permafrost Freeze-Back Pressure Behavior
Authors: Goodman Malcolm A. , Wood Donald B.
Published: December 2007

Drilling and production in the Arctic will thaw permafrost. At Prudhoe Bay on Alaska's North Slope the permafrost. At Prudhoe Bay on Alaska's North Slope the permafrost is nearly 2,000 ft thick. If thawed permafrost permafrost is nearly 2,000 ft thick. If thawed permafrost is allowed to freeze back, significant collapse loads near the bottom of the permafrost will be generated that must be considered in casing design. The loading mechanism is associated with the phase-change expansion of pore water in the thawed permafrost. The magnitude of the pressure buildup depends on the mechanical response of the frozen permafrost.

This article describes the formulation of an analytical freeze-back model and its correlation with freeze-back field-test data from Prudhoe Bay. As such, it is a condensed version of a paper in which the analytical model was formally developed. The model and field test yield the following conclusions.The 13 3/8-in., 72-lb, N-80 casing used in the field test and commonly used at Prudhoe Bay can safely withstand the maximum freeze-back pressures.For freeze-back from large thaw radii (50 ft of production thaw), the maximum pressure is not significantly production thaw), the maximum pressure is not significantly greater than that for freeze-back from small radii (3 ft of drilling thaw).The maximum freeze-back pressure depends on the elastic and yield properties of permafrost, but is most sensitive to the Young's modulus of frozen permafrost.Based on laboratory studies and supported by the field-test data, the creep or viscoelastic behavior of permafrost subject to freeze-back is negligible compared permafrost subject to freeze-back is negligible compared with the purely elastic and yield behavior.To limit the freeze-back pressure, the model is useful in the design of methods to limit the amount of initial thaw or to limit the extent of freeze-back.

The Freeze-Back Model

At each depth, the permafrost is initially thawed to a radius rb and, after refreezing for some time, is frozen back to radius ra. These two radii are input information to the model and serve to determine the amount of phasechange expansion at each instant in time. At the phasechange expansion at each instant in time. At the beginnig of freeze-back, the thawed permafrost is nearly saturated because of vertical drainage, water influx from drilling fluids, or compaction of the soil structure.

The freeze-back process occurs in three stages: relief of effective stress, elastic behavior, and elastic-yield behavior (see Fig. 1). In the first stage, as the pore water freezes, the ice either expands into the fluid-filled pores, increasing the porosity, and at the same time compressing the pore water, or expands locally, causing lens formation.

P. 949
Pore-Scale Modeling of Wettability Effects and Their Influence on Oil Recovery
Authors: Dixit A. B. , McDougall S. R. , Sorbie K. S. , Buckley J. S.
Published: December 2007

The wettability of a crude oil/brine/rock system influences both the form of petrophysical parameters (e.g., Pc and krw/kro) and the structure and distribution of remaining oil after secondary recovery. This latter issue is of central importance for improved oil recovery since it represents the "target" oil for any IOR process. In the present study, we have developed a three-dimensional network model to derive capillary pressure curves from nonuniformly wetted (mixed and fractionally wet) systems. The model initially considers primary drainage and the aging process leading to wettability alterations. This is then followed by simulations of spontaneous water imbibition, forced water drive, spontaneous oil imbibition and forced oil drive—i.e., we consider a complete flooding sequence characteristic of wettability experiments. The model takes into account many pore level flow phenomena such as film flow along wetting phase clusters, trapping of wetting and nonwetting phases by snapoff and bypassing. We also consider realistic variations in advancing and receding contact angles. There is a discussion of the effects of additional parameters such as the fraction of oil-wet pores, mean coordination number and pore size distribution upon fractionally and mixed wet capillary pressure curves. Moreover, we calculate Amott oil and water indices using the simulated curves. Results indicate that oil recovery via water imbibition in weakly water-wet cores can often exceed that obtained from strongly water-wet samples. Such an effect has been observed experimentally in the past. The basic physics governing this enhancement in spontaneous water imbibition can be explained using the concept of a capillarity surface. Based on these theoretical calculations, we propose a general "regime based" theory of wettability classification and analysis. We classify a range of experimentally observed and apparently inconsistent waterflood recovery trends into various regimes, depending upon the structure of the underlying oil- and water-wet pore clusters and the distribution of contact angles. Using this approach, numerous published experimental Amott indices and waterflood data from a variety of core/crude oil/brine systems are analyzed.
Comparisons of Cloud Point Measurement and Paraffin Prediction Methods
Authors: Monger-McClure T. G. , Tackett J. E. , Merrill L. S.
Published: December 2007

The performance and costs of deepwater developments can be compromised if paraffin deposition occurs in a subsea production system. Given the desirability of accurate cloud point measurement and paraffin prediction methods, and the consensus that available capabilities did not satisfy normal design-level confi- dence, DeepStar undertook an evaluation process. The primary goal was to use field experience (1) to devise guidelines for obtaining and using measured cloud points, and (2) to "ground truth" the various paraffin thermodynamic and deposition models in use within the industry.

Cloud point measurement studies showed that under preferred operating conditions, cloud points by each of four methods agreed with the average value of all methods within 3°F. The reproducibility for duplicate field samples run by the same method was about 5°F. When very slow cooling rates were not possible, an approximate supercooling correction in °F of 2 times the cooling rate in °F/min was determined. A five-component cloud point standard showed promise for method evaluation. A definite advantage was found to using more than one cloud point method for a given sample because wax-detection sensitivity was method- and crude-oil-dependent. There was good agreement between measured stock-tank oil (STO) cloud points and the highest temperature at which wax buildup was detected in the field.

Results for 10 paraffin thermodynamic models indicated several available models provided useful cloud point forecasts. A representative fluid sample was required to obtain data input for these models, including quantitative n-paraffin analysis using high-temperature gas chromatography. Comparisons of cloud point results for STO versus live oil suggested that the hotter (more conservative) STO predictions and measurements more closely approximated the fifield paraffin deposition experience.

Six paraffin deposition models correctly identified that wax would deposit and which wellbore had the higher buildup rate. However, predicted wax thicknesses and patterns of paraffin deposition varied widely, and could not be judged quantitatively using available field data. Overall, predicted maximum depths of paraffin deposition showed poor agreement with field observations.

Good field data for evaluating cloud point measurement and paraffin prediction methods were difficult to obtain, and additional work to field-validate paraffin deposition know-how is warranted.
Initiatives on Mercury
Authors: Pongsiri Nutavoot
Published: December 2007

Mercury has been known to be a trace contaminant in natural gas and condensate produced from Unocal Thailand's operations in the Gulf of Thailand since 1985. It has been detected in well streams, produced formation water, and also in solid waste. Mercury is recovered from process vessels, wellhead chokes, piping, and storage tanks. Almost all of the mercury found in natural gas and produced formation water is in elemental form, but in condensate, mercury is mostly in the colloidal form. Unocal Thailand has taken various proactive steps to minimize and limit both people's exposure to mercury and any impact on the environment, in full compliance with applicable laws and regulations. An example of environmentally sound treatment to dispose of mercury- contaminated solid waste is the deep-well injection technique. Another successful in-house developed technology, currently applied to the treatment of discharge water containing trace mercury, is a system using both gravitational separation and chemical flocculation techniques.
Large-Scale Two-Dimensional Imaging of Wettability Effects on Fluid Movement and Oil Recovery in Fractured Chalk
Authors: Graue Arne , Viksund B. G. , Baldwin B. A. , Spinler E. A.
Published: December 2007

The effect of embedded fractures on the movement and recovery of hydrocarbon from larger outcrop chalk blocks at different wettabilities has been measured in the laboratory. Two-dimensional (2D) nuclear tracer imaging was used to produce in situ fluid saturation distributions during oil production. Emphasis was on determining the oil recovery mechanisms by tracking the flow path of the advancing water. Two sequential waterfloods were performed on each of the three different blocks: first before fracturing, and then after fracturing. The same fracture network configuration was used for all three blocks, which were strongly water wet, moderately water wet, and near neutral wet. Waterflooding the unfractured blocks, at high initial water saturation, occurred with minimal water banking while waterflooding at low initial water saturation produced distinct water bank formation. Waterflooding of the fractured blocks showed that the "closed" fractures produced a significant effect on fluid movement in the strongly water wet block, but only minor effect for the moderately and near neutral wet blocks. The open fracture affected flow in all the blocks. Total oil recovery was higher in the strongly water-wet block than in the moderately water wet block with the lowest oil recovery observed in the near neutral wet block.
Water-Cut and Fractional-Flow Logs From Array-Induction Measurements
Authors: Ramakrishnan T. S. , Wilkinson D. J.
Published: December 2007

Despite the importance of relative permeabilities in reservoir simulation, no information regarding them is available from current logs. In this paper, for the first time, we demonstrate a continuous log of multiphase flow properties. Mud filtrate invasion is usually regarded as a process that corrupts the true logs. In reality, the multiphase flow characteristics that influence filtrate flow also determine the subsequent reservoir performance. We propose the notion that invasion is an experiment, albeit uncontrolled, that may be used to invert for multiphase flow properties. Thus, in principle, inversion of array induction measurements in terms of the fractional flow curve is possible. The forward model for filtrate invasion is based on two-phase (aqueous and oleic), three-component (oil, water and salt) transport. Hysteretic behavior of relative permeability functions is included. The radial conductivity profiles calculated from the flow model are converted to induction logs using radial response functions. An algorithm for rapid calculations of the forward logs by combining the electromagnetic and flow models is developed. A nonlinear least squares method is used for parameter inversion from measurements. Additional data of near-wellbore resistivity, or logs obtained during drilling, may be included. Presentations for several output logs have been developed: a reserves estimate that partitions porosity into residual and movable saturations, initial water cut in the production stream, the fractional flow curve as a function of saturation, filtrate loss per unit depth, and a quality indicator. A field example of the processing, and its comparison with production data is also discussed.
Brent Field Reservoir Modeling: Laying the Foundations of a Brown Field Redevelopment
Authors: James S. J.
Published: December 2007

The Brent Field was discovered in 1971. It is now a mature asset and, in order to increase oil and gas ultimate recovery, will commence depressurization in 1997. The redevelopment of the field has been underpinned by extensive static and dynamic modeling studies. Developments in geological computing and the numerical processing power of reservoir simulation platforms significantly improved the quality of the Brent Field static and dynamic models. The static models have been used for a range of studies including gas cap volumetrics and bypassed oil investigations. Their functionality provides significant scope for target sizing as a basis for selecting the appropriate reservoir access well technology.
Determination of Pressure-Transient and Productivity Data for Deviated Wells in Layered Reservoirs
Authors: Larsen Leif
Published: December 2007

Analytical methods are presented to determine pressure-transient and productivity data for deviated wells in layered reservoirs. The computational methods, which are based on Laplace transforms, can be used to generate types curves for use in direct analyses of pressure-transient data and to determine the effective skin of such wells for use in productivity computations.
Horizontal Underbalanced Drilling of Gas Wells with Coiled Tubing
Authors: Cox R. J. , Li Jeff , Lupick G. S.
Published: December 2007

Coiled tubing drilling technology is gaining popularity and momentum as a significant and reliable method of drilling horizontal underbalanced wells. It is quickly moving into new frontiers. To this point, most efforts in the Western Canadian Basin have been focused towards sweet oil reservoirs in the 900–1300 m true vertical depth (TVD) range, however there is an ever-increasing interest in deeper and gas-producing formations. Fig. 1 shows a composite vertical section of the horizontal or directional under-balanced wells drilled with coiled tubing in Canada, and also highlights the aforementioned trend towards oil over gas. Significant design challenges on both conventional and coiled tubing drilling operations are imposed when attempting to drill these formations underbalanced.

Coiled tubing is an ideal technology for underbalanced drilling due to its absence of drillstring connections resulting in continuous underbalanced capabilities. This also makes it suitable for sour well drilling and live well intervention without the risk of surface releases of reservoir gas. Through the use of pressure deployment procedures it is possible to complete the drilling operation without need to kill the well, thereby maintaining under-balanced conditions right through to the production phase. The use of coiled tubing also provides a means for continuous wireline communication with downhole steering, logging and pressure recording devices.

Coiled tubing drilling rigs currently exist in several different forms and setups, but generally consist of a drilling coil, injector to feed the tubing into or out of the well, (blowout prevention) (BOP) system for well control and return fluid path, and a control cab and power unit. The coiled tubing drilling equipment used to drill the case studies presented later in this paper consisted of either 60.3 or 73.0 mm coiled tubing and injector with a hydraulic power unit with control cabin and accumulator. A coiled tubing hybrid mast unit and substructure complete with V-door and catwalk was used. Pumping equipment included a fluid pumper capable of liquid rates of 0.10–1.5 m3/min, nitrogen pumper capable of 10–120 m3/min, and a nitrogen bulk storage unit of 50,000 m3 capacity. When drilling sour gas formations, a chemical injection pump for corrosion inhibition is typically used.
Analysis of Riserless Drilling and Well-Control Hydraulics
Authors: Choe Jonggeun
Published: December 2007

Riserless drilling is an unconventional technique using a relatively small diameter pipe as a mud return line from the sea floor instead of a large diameter marine riser. The schemes were developed in the late 1960s to reduce wear on blowout presenters and to make drill pipe re-entry easier by balancing internal and external subsea well pressures. However, these concepts were not implemented at that time because water depths were shallow, and technology was not available. In the Gulf of Mexico, exploration attempts have been made in areas which have more than 7,000 ft water depth. A conventional large diameter riser requires a vessel with huge weight and space capacities, large mud volumes to circulate through a riser, and numerous casing points because of the relatively low separation between the formation pore pressure and fracture pressure, especially in the Gulf of Mexico. These problems may be reduced significantly by applying riserless drilling. Therefore, riserless drilling is one of the attractive alternatives for economically exploring oil fields in deep water. The concept of riserless drilling currently has many unsolved problems such as system configuration and well control. This paper presents basic concepts of riserless drilling and a brief review of problems associated with conventional marine riser drilling for deep water applications. The paper also presents hydraulics and well control considerations for riserless drilling with comparison to conventional riser drilling.
Objectives of Engineering Education
Authors: Houston W.V.
Published: December 2007

Introduction

In recent years it has become customary to regard a university education as important for an engineer, but this has not always been the case. Engineering work has been done for thousands of years, and only for some 150 of them has it had any formal connection with universities. For several centuries the universities of Europe and the engineers of Europe had no connection with each other. Probably there are still a few practical men who look with considerable suspicion on a university graduate as he comes to an engineering job. And there are probably also a few university people who regard engineering departments as interlopers.

Engineering has two aspects and two traditions. One is the tradition of the master craftsman. It is a little hard to trace, historically, for its representatives rarely wrote books. They were builders and doers, rather than thinkers and talkers. But they did develop a strong sense of professional responsibility. Mistakes could not be tolerated. The art was handed down from master to apprentice and the road to mastery involved hard work. Experience was its measure.

The other tradition is a scientific and mathematical one. It is represented in ancient times by Plato's Academy and by the School at Alexandria. At the time of the Renaissance it comes to light in the faculties of philosophy in the universities and in the mathematicians attached to various courts. Today it is represented by the scientific and mathematical aspects of work in the universities. The men of this tradition were often, and are sometimes today, dismissed as merely theoretical, or impractical, by those who have had little understanding of the matters in which they find an absorbing interest. But from this group have come most of the strikingly new ideas of engineering.

And when men from this group have been able to establish close and sympathetic relationships with men of experience, engineering has leaped forward with great bounds.

Demands Upon the Engineer

The expansion of engineering in recent years has put severe demands on all sides of an engineer's proficiency.
Steam-Drive Correlation and Prediction
Authors: Myhill N.A. , Stegemeier G.L.
Published: December 2007

Introduction

During the past 15 years, steam-injection processes have become an importantmeans of exploiting heavy oil reserves. Traditionally, these processes havebeen classified as either steam soaks or steam drives. With combinations, suchas presoaking drive wells and partially driving steam soaks, the distinction isnot always applocable. Furthermore, our experience auggests that oil/steamratios from most mature processes converge to a calue determined only byreservoir and steam properties and time.

To date, the steam-soak process has proven the more attractive, partlybecause the immediate response allows an early evaluation of a reservoir andpartly because oil rates from initial soak cycles tend to be better than latercycles. Successful steam soaks are limited to reservoirs where natural recoverymechanisms (gravity drainage, pressure depeletion, and solition gas drive)areineffective because of the low oil mobilities.

Successful steam drives requiregood conformance,a means ofstarting the process because high oil saturations can limit injectivityseverely and prevent effective initial reservoir heating, andsustainedhigh injectivity throughout the process life. Unlike steam soaks, steam drivesdo not respond until built-up oil banks and heat reach the production wells.

Because peak production rates may not be observed for several years after thestart of injection, piloting is expensive and expansion to full scale issoemwhat hazardous. For those reasons, screening methods that predict ultimateoil/steam ratio are useful in planning new projects or in modifying existingones.

In the past, steam injection has been applied to a wide spectrum ofreservoir conditions, many of which have proven unsuitable. In retrospect, wecan explain the varied response withh a simple mathematical model thatincorporates reservoir and steam properties in the prediction. This paperdescribes the model and compares prediction from it with laboratory and fieldresults.
Reproducible Wettability Alteration of Low-Permeable Outcrop Chalk
Authors: Graue A. , Viksund B. G. , Baldwin B. A.
Published: December 2007

A total of 41 chalk core plugs, cut with the same orientation from large blocks of outcrop chalk, have been aged in crude oil at 90 °C for different time periods, in duplicate sets. Different filtration techniques, filtration temperatures and injection temperatures were used for the crude oil. Oil recovery by spontaneous, room temperature imbibition, followed by a waterflood, was used to produce the Amott water index for cores containing aged crude oil and for cores where the aged crude oil was exchanged by fresh crude oil or decane.

The main objective was to establish a reproducible method for altering the wettability of outcrop chalk. A secondary objective was to determine mechanisms involved and the stability of the wettability change.

The aging technique was found to be reproducible and could alter wettability in Rordal chalk selectively, from strongly water-wet to nearly neutral-wet. A consistent change in wettability towards a less water-wet state with increased aging time was observed.
The Successful Caprock Queen Water Flood - New Mexico's First
Authors: Riley E.A.
Published: December 2007

As a result of water flooding, some 30-million bbl of oil should ultimately be recovered from the Caprock Queen pool in southeastern New Mexico. The field is a consolidation of the Caprock Queen and Drickey Queen pools (Fig. 1), two separately discovered fields which were joined by subsequent drilling operations during their late primary lives. Practically the entire field is being flooded under unitized operation utilizing an 80-acre five-spot pattern contrived mainly by converting producers to injection status. Eight units have been formed and are injecting water. Only a few productive tracts are still nonunitized; however, efforts to place them in an offsetting unit are continuing. The advent of waterflood activity in New Mexico has added tremendously to the amount of recoverable oil reserves for the state. Obviously, these added reserves would be unrecoverable by primary production methods. Those units approved and injecting water prior to Nov., 1959, are operating under nonrestricted allowables, whereas those formed after this date are authorized to operate under a rule which carries allowable restrictions.

Introduction

Water injection as a secondary recovery technique has just passed its infancy in New Mexico. Although one earlier effort in the state had been reasonably successful, the two pilot floods initiated by Ambassador Oil Corp. and Graridge Corp. in the northern end of the Caprock field in late 1956 can justifiably lay claim to being the "trigger" of concerted waterflood efforts in the state. These two projects proved conclusively the Queen sand in this field could be successfully flooded. The highly impressive performance of the two pilot floods resulted in their inclusion in unitized operations. Unitization efforts then progressed southward, leading to the formation of eight units-seven consisting of wells mainly drilled during primary development and one, the Pebble Queen Unit, containing wells which resulted from secondary-stage "fringe drilling" along the western edge of Unit No. 2 (Fig. 2). Obviously, other undrilled locations along edges of the field will be developed, particularly along the central sector. Unit Nos. 1, 2 and 3 and the John Trigg project operate under the old allowable rule which permits high injection and production rates. The Drickey Queen was injecting water prior to the Roswell (N. M.) hearing but has chosen to operate under Rule 701. The other units commenced injecting water after Nov., 1959; consequently, they operate under the latter rule.

Location

The Caprock-Drickey pool is located along and adjacent to the boundary line between Lea and Chaves counties, N. M., in Townships 12, 13, 14 and 15 South Range 31 East, and Townships 12 and 13 Range 32 East.

JPT

P. 1195^
Brine Disposal Into a Tight Stress-Sensitive Formation at Fracturing Conditions: Design and Field Experience
Authors: Settari Antonin , Warren G. M. , Jacquemont Jerome , Bieniawski Paul , Dussaud Michel
Published: December 2007

This paper describes a study of the potential of a tight reservoir zone for disposal of brine generated in salt cavern leaching operations. The study included field injection testing, numerical analysis using uncoupled and coupled reservoir, geomechanical and fracturing modeling, laboratory work and design of a field injection monitoring program. It was shown that a surprising brine disposal capacity exists in the tight (0.03 md) Oriskany target formation. Initial screening was followed by carefully designed injection testing, laboratory work and subsequent evaluation with the aid of detailed coupled fracture and reservoir numerical models, and numerical well test analysis. Low initial estimates of brine disposal capacity were increased significantly by incorporating more sophisticated, coupled reservoir and geomechanical numerical models. The models, which account for stress dependent porosity and permeability and fracture propagation, were calibrated to laboratory and field test data. Using these models, an excellent match of the injection data was obtained, and predictions of injectivity were made under various project scenarios. The coupled model has been also used to design the monitoring program for the first phase of the injection operations.
Prediction of Permeability from the Skeleton of Three-Dimensional Pore Structure
Authors: Liang Z. R. , Philippi P. C. , Fernandes C. P. , Magnani F. S.
Published: December 2007

The main purpose of the present work is to predict the permeability of a porous medium from its three-dimensional (3D) porous structure network. In this work, 3D porous structure is reconstructed by the truncated Gaussian method using Fourier transform and starting from a 2D binary image obtained from a thin section of a porous sample. The skeleton of the 3D porous structure provides a way of visualizing the graph of the pore network. It is determined using a thinning algorithm, which is conceived to preserve topology. It gives both visual and quantitative information about the connectivity of the pore space, the coordination number for every node and local hydraulic radius. Once the network of the pore structure is obtained, the macroscopic transport properties, such as the permeability, can be predicted. The method is applied to a 500 mD Berea sandstone and the predicted permeability is in good agreement with the experimental value and empirical correlations.
Reservoir Characterization as a Risk-Reduction Tool at the Nash Draw Pool
Authors: Martin F. D. , Murphy M. B. , Stubbs B. A. , Uszynski B. J. , Hardage B. A. , Kendall R. P. , Whitney E. M. , Weiss W. W.
Published: December 2007

Recently acquired geological, geophysical, and engineering data at the Nash Draw Brushy Canyon Pool revealed that the initial reservoir characterization was too simplistic to capture the critical features of this complex Delaware formation. A new reservoir description provides sufficient detail to indicate that compartmentalization exists in the Brushy Canyon interval. This new reservoir description is being used to identify "sweet spots" for a development drilling program as well as to optimize reservoir management strategies. This paper presents recent results of an integrated reservoir characterization effort that is being used at Nash Draw as a risk reduction tool.