bluuebunny/crossref_metadata_2025 huggingface dataset:
History Match Analysis of the Little Creek CO2 Pilot Test
Authors: Youngren Gary K. , Charlson Gary S.
Published: December 2007

Production and pressure data from the Little Creek CO2 miscible pilot test are history matched using a miscible flood simulator. Simulated recovery is dominated by gravity segregation of CO2 and crossflow of oil. A new pseudorelative permeability technique, which decouples gravitational and viscous fingering effects, is developed and used in the history match.

Introduction

A limited number of carbon dioxide miscible pilot tests have been completed or have enough history to permit a meaningful evaluation. Noteworthy tertiary examples include the SACROC, Twofreds, and Willard tests in west Texas and the Little Creek test in Mississippi. SACROC, Twofreds, and Little Creek were producing pilots; of these, the Little Creek pilot is best suited for a thorough analysis to identify those factors that influenced tertiary oil recovery. The test was well confined and small, with one injector and three producers.The primary objective of this work was to determine the controlling factors in the Little Creek CO2 flood by history matching pressure and production data with a four-component, miscible flood simulator. Additional objectives were to (1) develop, demonstrate, and employ a pseudorelative permeability technique for simulating three dimensional miscible performance with two-dimensional calculations and (2) project performance for different-size CO2 slugs than that tested at Little Creek.

Field Description and History

The characteristics and history of the Little Creek field are documented elsewhere. A limited discussion of the field is presented here for completeness.The Little Creek field is in the Lower Tuscaloosa trend of southwestern Mississippi. It was discovered in 1958. A peripheral line-drive waterflood was conducted from 1962 to 1970, and CO2 was injected into the pilot area from Feb. 1974 to Feb. 1977. Of the 102 million bbl (16.2 x 10(6) m3) of oil initially in place, 25 million bbl (4.0 x 10(6) m3) were produced by primary depletion and 22 million bbl (3.5 x 10(6) m3) were produced as a result of waterflood operations. More than 120,000 bbl (19 000 m3) were produced in the pilot test.The reservoir's pay zone is the 10,750-ft (3280-m) Lower Tuscaloosa Denkman sand, which is Cretaceous in age. The reservoir is controlled stratigraphically, being limited by rapid sand pinchout on the flanks. The reservoir is said to have "remarkably uniform rock properties ... (with) no correlative high permeability zones." The reservoir responded very well to water injection, reportedly "flooding out uniformly ... going to 100% water within 3 months of flood-front breakthrough and conformance was estimated to be 90%" Table 1 lists average rock and fluid properties.The CO2 miscible pilot test was conducted against a pinchout along the eastern edge of the field. As shown in Fig. 1, the pattern is essentially one-quarter of an inverted nine-spot on 40-acre (16-ha) spacing. The pilot area was confined by five backup water-injection wells whose purpose was to prevent migration of fluids out of the test pattern.

JPT

P. 2042＾
Wellbore Storage Effects in Geothermal Wells
Authors: Miller Constance W.
Published: December 2007

The early-time response in the well testing of a homogeneous reservoir customarily is expected to give a unit slope when the logarithm of pressure is plotted vs. the logarithm of time. It is shown that this response is a special case and that another non-dimensional parameter must be defined to describe the set of curves that could take place for each value of the wellbore storage coefficient CD. In addition, the effect of temperature changes along the bore is shown to increase the time when wellbore storage is important.
Imparting Directional Dependence on Log-Derived Permeability
Authors: Schön J. H. , Georgi D. T. , Fanini O.
Published: December 2007

Cost-effective, efficient production of hydrocarbons depends on accurate reserves estimates, reservoir architecture, and hydrocarbon distribution. In addition, a complete reservoir description, including both horizontal and vertical permeability, is critical to efficient development strategy. Hydrocarbon recovery efficiency depends on many factors, but one key parameter is the ratio of vertical to horizontal permeability.

There are numerous ways to estimate permeability. It is now possible to estimate permeability from continuous formation evaluation measurements. However, it remains difficult to determine directional permeability. Nuclear magnetic resonance (NMR) logs are used routinely to estimate permeability, but NMR-derived permeability is based on scalar properties (e.g., ϕ, T2 distributions from NMR, and bulk volume irreducible water) and is inherently a scalar property itself.

Few formation evaluation measurements provide directional information. Dip and image logs provide bed thickness and layer dip information, while the multicomponent induction instrument (3DEX*) and crossed-dipole shear-wave acoustic tools provide direct measurements of macroscopic formation anisotropy.

In this paper, we explore theoretically and with real data the computation of permeability anisotropy. We use laminated sand models as well as macroscopic models based on the resistivity anisotropy measurements to estimate kV:kH ratios. In addition to multicomponent induction data, we explore stand-alone and joint interpretation of NMR property variations to predict the macroscopic reservoir permeability anisotropy.
Unconventional Miscible EOR Experience at Prudhoe Bay: A Project Summary
Authors: McGuire P. L. , Holt B. M.
Published: December 2007

This paper describes the conceptual development, reservoir simulation, and field testing of a new miscible enhanced oil recovery (EOR) technique at Prudhoe Bay. Two distinct variations of this technique have been evaluated.

The vertical Miscible Injectant Stimulation Treatment (MIST) process involves completing a production well at the bottom of a thick, continuous, watered-out interval. A large slug of miscible injectant (MI) is injected, followed by a small slug of chase water. The MI sweeps rock not contacted by previous MI injection and drives EOR oil to offset producers.

In the lateral MIST process, a horizontal lateral is drilled along the base of the reservoir from either a production well or an injection well. MI is injected sequentially into several intervals along the lateral to mobilize EOR oil from previously unswept areas. The lateral well is then returned to normal production or injection service.

Simulation data indicated that the vertical MIST process could recover more than 200,000 STB of incremental oil per well at initial rates of up to 1,000 STB/D. Calculations for the lateral MIST process indicated potential recovery of more than 1 million bbl of incremental EOR per lateral.

Field results of the MIST process have been mixed but are encouraging overall. Incremental EOR response from the first MIST lateral well through July 2000 was approximately 1,400,000 STB, resulting in a technical and economic success.

Response from three subsequent MIST lateral injectors varied widely. The first vertical well MIST showed little response, but it did provide valuable insight into the performance of the process at Prudhoe Bay. The subsequent vertical well MIST, which had a much larger volume of injected MI, was very successful and has currently recovered over 1,100,000 STB. Cumulative incremental EOR from the MIST wells through July 2000 was more than 5,000,000 STB, with average incremental oil-production rates of approximately 4,000 STB/D. Based on these successful results, an ongoing program of additional MIST wells is planned.
A Study of Vibratory Screening of Drilling Fluids
Authors: Hoberock L.L.
Published: December 2007

This work presents results of an experimental and theoretical study ofvibratory screening of bentonite/water drilling fluids containing amedium-fine fracturing sand to simulate granular drilled solids. Satisfactory solids conveyance off the screen can be obtained for flat decks if the vibrator is placed to yield proper phasing between the normal and tangential acceleration components at all points on the vibrating deck.

Introduction

Drilling fluids returning from a well during drilling are passed serially through a number of solid/liquid separation devices to maximize removal of drilledsolids from the fluid before reuse. The vibratingscreen or shale shaker, the first device to process thefluid, removes the largest particles. Othersolids-separation equipment in the surface mud system can operate efficiently only if the shale shaker is performing properly. Consequently, it often is considered the most important solids-control device on a drilling rig. Most, if not all, of the various shaker designs now available have evolved from vibrating screens used in other industries, primarily the mining industry. Because of its obvious importance in such industries, vibratory screening has been the subject of numerous studies and investigations. On the other hand, very little investigative work has been published on vibratory screening of drilling fluids. The essential difference between this type of screening and that in other industries is that most of the material processed by a drilling fluid screen is liquid, rather than solid. For example, a well-maintained drilling fluid could have less than 10% tool solids by volume. Consequently, much of the existingtechnology for vibratory screening of dry solids, or even very wet slurries, does not apply toscreening of drilling fluids. The importance of this problem has been recognized by the IADC, which recently sponsored a conference on vibrating screen separators. Because the screen cloth itself is critical in determining the amount and size of solids removed by a shale shaker, the API has published a recommended practice for designating shale shaker screen cloth. More recently, Cagle and Wilder reported results of an experimental comparison between two commercially available shakers, primarily to evaluate a new design in screening cloth. Beyond this study, however, comprehensive investigations of the problem apparently have not been published.

JPT

P. 1889＾
How Bit Profile and Gauges Affect Well Trajectory
Authors: Menand S. , Sellami H. , Simon C. , Besson A. , Da Silva N.
Published: December 2007

The importance of wellbore deviation is well recognized by the drilling industry. An analysis of a drilling system's directional behavior must include the directional characteristics of the drill bit. This paper presents a comprehensive analysis of the directional behavior of polycrystalline diamond compact (PDC) bits, including the effect of bit profile, gauge cutters, and gauge length. Numerical simulations as well as laboratory tests have been carried out to better understand the mechanisms of PDC bit deviation and to evaluate the most important parameters affecting the directional behavior of PDC bits.

The analysis presented in this paper shows that each part of the PDC bit (profile and active and passive gauges) plays a major role in its walking tendency and steerability. A quantitative evaluation of how these factors contribute to well trajectory (inclination and azimuth) is given.

For the first time, a full-scale directional-drilling bench was built to measure the walking tendency and steerability of PDC bits. The results obtained demonstrate that the bit profile, gauge cutters, and gauge length have a significant effect. A 3D theoretical rockbit interaction model was developed to reproduce the drilling test results.
History Matching in Two-Phase Petroleum Reservoirs
Authors: Watson A. T. , Seinfeld J. H. , Gavalas G. R. , Woo P. T.
Published: December 2007

An automatic history-matching algorithm based on an optimal control approach has been formulated for joint estimation of spatially varying permeability and porosity and coefficients of relative permeability functions in two-phase reservoirs. The algorithm uses pressure and production rate data simultaneously. The performance of the algorithm for the water-flooding of one- and two-dimensional hypothetical reservoirs is examined, and properties associated with the parameter estimation problem are discussed.
Comparison of Sensitivity Coefficient Calculation Methods in Automatic History Matching
Authors: Dogru Ali H. , Seinfeld John H.
Published: December 2007

The efficiency of automatic history matching algorithms depends on two factors: the computation time needed per iteration and the number of iterations needed for convergence. In most history matching algorithms, the most time-consuming aspect is the calculation of the sensitivity coefficients – the derivatives of the reservoir variables (pressure and saturation) with respect to the reservoir properties (permeabilities and porosity). This paper presents an analysis of two methods – the direct and the variational – for calculating sensitivity coefficients, with particular emphasis on the computational requirements of the methods.

If the simulator consists of a set of N ordinary differential equations for the grid-block variables (e.g., pressures) and there are M parameters for which the sensitivity coefficients are desired, the ratio of the computational efforts of the direct to the variational method is

R = N ( M + 1 ) N ( N + 1 ) + M .

Thus, for M<N the direct method is more economical, whereas as M increases, a point is reached at which the variational method is preferred.
Investigation of Three-Phase Regions Formed by Petroleum Sulfonate Systems
Authors: Blevins Creed E. , Willhite G. Paul , Michnick Michael J.
Published: December 2007

The three-phase region of the Witco TRS 10–80 sulfonate/nonane/isopropanol (IPA)/2.7% brine system was investigated in detail. A method is described to locate phase boundaries on pseudoternary diagrams, which are slices of the tetrahedron used to display phase boundaries of the four-component system.

The three-phase region is wedge-like in shape extending from near the hydrocarbon apex to a point near 20% alcohol on the brine/alcohol edge of the tetrahedron. It was found to be triangular in cross section on pseudoternary diagrams of constant brine content, with its base toward the nonane/brine/IPA face. The apex of the three-phase region is a curved line where the M, H + M, and M + W regions meet. On this line, the microemulsion (M*) is saturated with hydrocarbon, brine, and alcohol for a particular sulfonate content. A H + M region exists above the three-phase region, and an M + W region exists below it.

Relationships were found between the alcohol concentration of the middle phase and the sulfonate/alcohol and sulfonate/hydrocarbon ratios in the middle phase. These correlations define the curve that represents the locus of saturated microemulsions in the quaternary phase diagram. Alcohol contents of excess oil and brine phases also were correlated with alcohol in the middle phase.

Pseudoternary diagrams for sulfonates are presented to provide insight into the evolution of the three-phase region with salinity. Surfactants include Mahogany AA, Phillips 51918, Suntech V, and Stepan Petrostep™ 500. Differences between phase diagrams follow trends inferred from comparisons of equivalent weights, mono-/disulfonate content, optimal salinity, and EPACNUS values.
Effect of Temperature on Surfactant Adsorption in Porous Media
Authors: Ziegler Victor M. , Handy Lyman L.
Published: December 2007

The effect of temperature on the adsorption of a sulfonate surfactant and a nonionic surfactant onto crushed Berea sandstone was studied by both static and dynamic techniques.

Static experiments were conducted over a temperature range from 25 to 95 °C to define temperature-sensitive rock/surfactant systems and to establish the shape of the equilibrium isotherm. Dynamic experiments served to reinforce the findings of the static tests and extended the temperature range for sorption to 80°C. This is a typical steamflood temperature. A mathematical model that incorporates the mass transport, thermal degradation, and rate-dependent adsorption of the surfactant represented these dynamic results. The model was used to determine the effect of temperature on the sorption rate constants.

Mineral dissolution at elevated temperatures has been found to cause precipitation of the sulfonate. Adsorption of the nonionic surfactant decreased with an increase in temperature at low concentrations, whereas the opposite was true at high concentrations. This has favorable implications for a low-concentration injection scheme. When performing static adsorption experiments, care had to be taken because of the poor thermal stability of the nonionic surfactant.
Combined Analysis of Postfracturing Performance and Pressure Buildup Data for Evaluating an MHF Gas Well
Authors: Bostic James N. , Agarwal Ram G. , Carter Robert D.
Published: December 2007

This paper presents a method of combining postfracturing performance datawith postfracturing buildup data for analysis on the same constant-ratetype curve. This combination of buildup and production data isaccomplished through the use of the superposition principle. The method allows the use of production data that contain occasional shut-in periods of long duration.

Introduction

Low-permeability (less than 0.1 md) gas wells mustbe stimulated with massive hydraulic fracture (MHF)treatments to be commercial. Once a well has beenstimulated, it is important to determine the lengthand conductivity of the resulting fracture asaccurately as possible to predict rates and reserves andevaluate the effectiveness of the stimulation.

Two types of data normally are available toperform the required analysis. The first type isroutinely collected data such as gas flow rates and flowing wellhead pressures. The second type of datais that from specially designed tests such as pressurebuildup tests. There are various methods availablefor analyzing both kinds of data, but all of themethods have certain limitations.

Current analysis techniques are satisfactory forfinite-flow-capacity fractures when formation flowcapacity kh is known and sufficient production datawithout shut-in periods is available to perform atype-curve match as shown by Cinco et al. andAgarwal et al. However, one disadvantage of MHFtreatments is that they often cause the stimulatedwells to produce large volumes of load water(returning fracture fluids) for several weeks ormonths. Production data obtained during thiscleanup period usually are not applicable fortype-curve matching purposes with the currently available type curves. Since type curves normally are plottedon a log-log scale and exhibit the most character atsmall dimensionless times, the loss of the early-timeproduction data disproportionately reduces thelength of the available data band and is critical to theproblem of obtaining a satisfactory match.

The purpose of this paper is to present a method ofcombining the production and buildup test data sothat their concurrent analysis overcomes some of thelimitations of either individual data set. Thesuperposition principle is used in this combination, and the analysis of the resulting data set shouldprovide a more accurate result than previouslypossible. This combination has the potential togenerate field data curves of sufficient length that theshape of the data curve may be sufficiently definitive to determine formation flow capacity by type-curveanalysis. Additionally, this method makes it possibleto use production data that contain occasional shut-in periods of long duration.

JPT

P. 1711＾
Analysis of Pressure Data From Vertically Fractured Injection Wells
Authors: Bennett Curtis O. , Reynolds Albert C. , Raghavan Rajagopal
Published: December 2007

This study investigates the flowing and shut-in pressure behavior of a fractured well located in a square drainage region with the outer boundary at a constant pressure. The fracture plane lies on one of the diagonals of the square. The report shows how to analyze pressure data for a five-spot pattern when the fracture orientation is most favorable (from the viewpoint of sweep efficiency). Comparisons are made with studies in the literature that assume an unfavorable fracture orientation. Fracture orientation must be considered in the analysis of pressure data for the following conditions: (1) small fracture-penetration ratios, (2) large flowing times prior to shut-in, and (3) large values of fracture flow capacity.

Insights into the application of type-curve analysis to estimate drainage volumes are presented. Claims in the literature regarding the determination of the drainage volume by type-curve matching appear to be unrealistic.
An Equation of State Compositional Model
Authors: Coats Keith H.
Published: December 2007

This paper describes an implicit, three-dimensional formulation for simulating compositional-type reservoir problems. The model treats three-phase flow in Cartesian (x-y-z) or cylindrical (r-θ-z) geometries. Applicability ranges from depletion or cycling of volatile oil and gas condensate to miscible flooding operations involving either outright or multicontact-miscibility.

The formulation uses an equation of state for phase equilibrium and property calculations. The equation of state provides consistency and smoothness as gas- and oil-phase compositions and properties converge near a critical point. This avoids computational problems near a critical point associated with use of different correlations for K values as opposed to phase densities.

Computational testing with example multicontactmiscibility (MCM) problems indicates stable convergence of this formulation as phase properties converge at a critical point. Results for these MCM problems show significant numerical dispersion, primarily affecting the calculated velocity of the miscible-front advance. Our continuing effort is directed toward reduction of this numerical disperson and comparison of model results with laboratory experiments for both MCM and outright-miscibility cases.

We feel that the implicit nature of the model enhances efficiency as well as reliability for most compositional-type problems. However, while we report detailed problem results and associated computing times, we lack similar reported times to compare the overall efficiency of an implicit compositional formulation with that of a semi-implicit formulation.
Experimental Study of Severe Slugging in a Two-Phase-Flow Pipeline - Riser Pipe System
Authors: Schmidt Zelimir , Brill James P. , Beggs H. Dale
Published: December 2007

Slug flow was studied in a simulated, offshore, pipeline-riser pipe system. Two distinct slug flow patterns were identified: severe slugging and normal slug flow. Severe slugging, characterized by generation of slugs ranging in length from one to several riser pipe heights, occurs at low gas and liquid flow rates and for negative pipeline inclinations. A mathematical model was developed for severe slugging. Results agree well with experimental data. Choking was found to be an effective method of eliminating severe slugging.
Biological Oxidation of Dissolved Compounds in Oilfield Produced Water by a Field Pilot Biodisk
Authors: Palmer L.L. , Beyer A.H. , Stock J.
Published: December 2007

Besides small amounts of suspended oil, oilfieldproduced water after conventional treatment cancontain dissolved organic and ammonium compounds that may preclude its discharge into the oceanbecause of environmental protection regulations.Two field pilot studies in southern California established the technical feasibility and cost ofremoving these dissolved compounds by biologicaloxidation in a biodisk. Effluent from the two pilot plants complied with all requirements of Californialaw.

Introduction

Despite the lack of documented adverse effects fromnormal petroleum operations, environmentalprotection regulations have been adopted that limitthe offshore discharge of produced water. The WaterQuality Control Plan for the Ocean Waters ofCalifornia (CWQCP), adopted in 1972 andamended in 1978, regulates all domestic andindustrial wastewaters discharged within California's3-mile (5.5-km) zone. The CWQCP includes effluentlimits on oil and grease, dissolved phenols, dissolvedammonium compounds, and toxicity to marine life.U.S. guidelines proposed in 1975 for the onshore petroleum industry by the Environmental ProtectionAgency would require"zero pollutant discharge"inside the 3-mile (5.5-km) zone by 1983.

Previous publications have reported thecompositions of oilfield produced waters. Workdone by Chevron shows that typical produced watersfrom the U.S. west coast and the Gulf of Mexico, after oil removal by gravity separation and/orflotation, have compositions ranging from 20 000 to135 000 g/m3 TDS, 45 to 130 g/m3 ammonia (as N), and 0.1 to 3.0 g/m3 phenols (as C6H5OH). Conventionaloilfield water-separation processes are notdesigned to remove these dissolved compounds, andother treatment processes are needed where disposalrestrictions on such compounds exist.

Biological oxidation uses harmless bacteria, algae, fungi, and protozoa to convert dissolved organic andammonium compounds into water plus CO2 andnitrates/nitrites, respectively. A field pilot studyof an aerated lagoon conducted at Carpinteria, CA, demonstrated the feasibility of biological oxidationfor removing dissolved compounds such as ammoniaand phenols from produced waters. This paperdescribes two field pilot studies conducted insouthern California that demonstrated, for the firsttime, the feasibility of another biological oxidationtreatment process - the rotating biological surface(biodisk).

JPT

P. 1136^
Calcite Control in In-Situ Uranium Leaching Process
Authors: Yan T.Y.
Published: December 2007

A method has been developed to control the problem of calcite deposits inthe in-situ uranium leaching process using carbonates as the lixiviant. Achemical inhibitor is added to the calcium-supersaturated lixiviant (andother process streams) at critical locations in sufficient quantity to forma metastable solution of calcite so that the lixiviant can pass throughcritical areas without depositing calcite.

Introduction

Uranium values can be recovered from undergrounddeposits by open-pit or underground miningfollowed by milling or leaching in a surface mill. Recently, the efficient recovery of uranium fromsedimentary deposits also has been accomplished byin-situ leaching or solution mining. The in-situ leaching process integrates the standard mine/millcomplex by in-place leaching of uranium andprocessing the uranium-rich fluids at the surface. Useof an in-situ leaching process for sedimentaryuranium deposits has proved profitable andcompetitive with the conventional open-pit orunderground mine/mill systems. The advantages ofthe in-situ leaching process have been reviewed.

The nature of the lixiviant for successful in-situleaching depends on the nature of the ore bodies.Acid lixiviant, consisting of H2SO4 and NaClO3, has been tested successfully at Shirley basin inWyoming. Sulfuric acid and H2O2 lixiviant has beenused with success at Nine Mile Lake in Wyoming byRocky Mountain Energy Co. For ores with a highcontent of carbonate minerals, such as limestone anddolomite, the acidic lixiviants become uneconomical because of excess acid consumption. For such ores, carbonate lixiviant is preferred.

In the carbonate leaching process, the lixiviantsare made up of NaHCO3/Na2CO3 as the complexingagents and NaClO3 or H2O2 as the oxidant.However, in the field a permeability loss often isencountered when NaHCO3/Na2CO3 lixiviant isused. This permeability loss is thought to be due toswelling of clay minerals, such as smectite, in theformation by sodium ion. Use of ammonium ion inplace of sodium ion in the lixiviant can alleviatemuch of the problem of formation permeability loss.Intercontinental Energy Corp. has been successfullyusing (NH4)2CO3 and H2O2 as the lixiviant in southTexas for some time. Mobil Oil Corp. alsosuccessfully pilot tested the use of(NH4)2CO3 andNaClO3 in south Texas.

JPT

P. 2068＾
Planning the Directional Well - A Calculation Method
Authors: McMillian William H.
Published: December 2007

This paper describes a radius-of-curvature calculation of the three-dimensional (3D) path of a directionally drilled well from kickoff point to target. Slant-well, S-shape, and maximum turn well paths can be computed. Equations are developed for calculating critical points along the well path in terms of cartesian coordinates and directional survey parameters. The effect of right-hand walk (drift) and a technique for calculating the appropriate lead to compensate for drift is presented.

Introduction

In contrast to the many references on methods for calculating directional surveys, there is a notable absence of articles discussing the related problem of well planning. Wilson derived the concept of compounded wellbore curvature in discussing the curvature method to calculate directional surveys. However, no 3D method has been published to handle the calculation of well paths that have both changes of azimuth and changes of inclination. This is a common type of well path, especially in sidetracked holes and for drilling around salt domes. The intent of this paper is to describe a procedure that will accommodate the 3D geometry of practical well trajectories.

The general solution assumes that all curvatures between two points are constant. The only other limitations imposed are a maximum curvature and a maximum inclination.

Radius-of-Curvature Equations

The radius-of-curvature method used in this procedure is a preferred approach to well-path calculation because of its relative simplicity and general use in the industry for interpreting directional surveys. It also appears to conform to the geometry of directional drilling since the objective of turning a well with, for example, a bent sub and downhole mud motor is to drill a well path with constant radius of curvature. Rivero has generalized the radius-of-curvature equations to the following form.

Cases 1 and 2.

(1)

Case 1. .

(2)

(3)

This case represents a constant curvature in azimuth as well as inclination.

JPT

P. 952^
The Application of the Buckley-Leverett Frontal Advance Theory to Petroleum Recovery
Authors: Dardaganian Stephen G.
Published: December 2007

Introduction

Basically, the Buckley-Leverett theory involves two systems which are similar in nature but are differentiated by time. These systems may be described by the fractional flow and frontal advance equations which essentially characterize the mechanics of oil movement while being expelled from the reservoir.

The fractional flow equation originally developed by Leverett may be expressed in the more usable form

(Equation 1).

The development of this equation is based on Darcy's law describing fluid flow through porous media and applies to the flow at only one point (it is a point function). For simplification, the fractional flow equation is written in the above form because the capillary forces always increase the fractional flow of the displacing phase regardless of the direction of flow or the displacing phase.

Applications of the Frontal Advance Theory to Petroleum Recovery

Two general applications of the Buckley-Leverett frontal advance theory involve the system in which the oil is being displaced by an expanding gas cap overlying the oil zone and that in which the oil is being displaced by water.

Displacement by Gas in the Presence of an Immobile Water Saturation

A system in which gas is the displacing phase may be thought of as having two forces effecting the displacement process. These forces are the gravitational force and that force exerted by the displacing gas. The gravitational effects control the displacing efficiency of the gas. The gravitational effect will be less at higher rates of flow, thereby reducing the effectiveness of the displacement of the oil by the gas. The more efficient displacements occur at flow rates which are less than the gravity free fall rate. Capillary forces can be neglected without materially changing the magnitude of the gas saturation.

The Mile Six pool is used herein to illustrate the calculating procedures in evaluating gas drive-gravity drainage field performance. These calculations represent the determination of the gas-oil contact when the distribution of the hydrocarbon pore volume is considered.
Application of Reliability Analysis Techniques to Intelligent Wells
Authors: Drakeley Brian K. , Douglas Neil I. , Haugen Knut E. , Willmann Endre
Published: December 2007

This paper describes the overall methodology and quantitative techniques applied during the development of an intelligent well control and communication system to ensure high system reliability and availability. In particular, the anticipated reliability impact of introducing high-temperature (HT) electronics technology together with redundancy for critical components is quantified.

One of the main challenges when analyzing the reliability performance of novel technology is to establish appropriate input data. Hence, a methodology applied to establish and validate reliability data is presented.

Harsh installation and operating conditions make a zero failure expectation for a 10-year life span appear unrealistic. The solution to this paradox is to assume that there will be some failures and to combat this by developing a highly fault-tolerant system.

The methodology described in this paper also has broader potential applications to other oil and gas system development projects. It brings to our industry practices that are frequently employed in the aerospace and nuclear industries.
Logs From P and S Vertical Seismic Profiles
Authors: Omnes Gildas
Published: December 2007

Vertical seismic profiles differ from ordinary well velocity surveys, or check shots, in two aspects: the records are longer and the depth intervals between measurements are much shorter. Accurate picking of first breaks makes the plotting of P and S velocity logs possible. From the velocity logs, a vs/vp log can be calculated.

Introduction

A vertical seismic profile (VSP) is the seismogram obtainable by lowering a multitrace seismic array in a well, activating a seismic source near or on the surface, and recording the seismic sensors during a time equal to at least twice the travel time between the surface and the deepest mirrors.Probes presently in use are not more than a few feet long, and the VSP seismogram is obtained by clamping the probe against the walls at regularly spaced depths and activating the seismic source for each position of the probe.Fig. 1 shows the three kinds of seismic signals detected at a geophone (receiver) R placed in a well when a source S located on the surface is activated:direct wave causing the first breaks,up-going reflections, anddown-going reflections resulting from the reflection of up-going waves by mirrors located above R.Fig. 2 shows how these events line up on a VSP seismogram.

The left-hand sketch shows ray paths corresponding to two locations of the probe R1 and R2, with R1 above R2. Down-going waves, first breaks, and down-going reflections reach R1 before R2. Their lineups have parallel slopes within a given velocity interval. Up-going reflections reach R2 before R1. The transit time is the same as in the case of down-going events, but the slope of the lineup on the seismogram has the opposite sign.Though field operations are basically the same, there are two main differences between VSP's and ordinary well velocity surveys, or check shots:the recording time is much longer in the case of VSP'S, andthe depth interval between successive locations of the probe is shorter in the case of VSP's 15 to 70 ft (5 to 20 m) vs.

165 to 650 ft (50 to 200 m), or even more in the case of ordinary check shots.VSP's generally are recorded in view of a study of the reflection phenomena at a given location. Good VSP's make possible the direct observation of attenuation, multiple reflections, correlation of P and S events, etc. Also, the short spacing between recording stations makes it possible to obtain transit time logs based on the accurate picking of first breaks. When both P and S events are recorded, elasticity moduli can be estimated, and a much more accurate knowledge of the lithology is made possible. It is the purpose of this paper to illustrate, through the study of an example, how interesting logs can be obtained from P and S VSP's recorded in the same well.

VSP Displays and Records

Figs. 3 and 4, respectively, correspond to P and S VSP's recorded in the same well. The stratigraphic series listed in Table 1, and indicated on the left side of each figure, is typical of the central part of the Paris basin in France. Depths indicated in Table 1 are exact depths in the considered well.

JPT

P. 1843＾
Gas- and Liquid-Phase Relative Permeabilities for Cold Production From Heavy-Oil Reservoirs
Authors: Tang Guo-Qing , Firoozabadi Abbas
Published: December 2007

Solution-gas drive with two heavy oils, a mineral oil with a viscosity of some 32,000 cp (at 24°C), and a heavy crude with viscosities of 85,000 cp and 9,200 cp (at 24 and 35°C, respectively) is carefully studied. Both oils show recovery in excess of 10% at test termination; the recovery for the heavy crude exceeds 15%. Had we continued the test, the recovery could have been higher.

From the measured pressure and fluid-flow rates, gas and oil relative permeabilities are estimated by a simple mathematical expression. The results establish that high recoveries are mainly caused by the low gas relative permeability. The results on mineral oil and heavy crude also demonstrate that the widely held belief that efficient solution-gas drive in heavy crude is caused by the foamy nature cannot be justified. An increase in temperature would reduce the oil viscosity, which in turn increases the gas mobility, thereby reducing the efficiency of solution-gas drive for cold production.
Integrated Optimization on a Long Horizontal Well Length
Authors: Cho Hyun
Published: December 2007

This paper presents a methodology developed to estimate the optimum horizontal well length based on total economics and on the productivity index (PI) change associated with frictional loss effects in the long section of the horizontal wellbore. An integrated approach is proposed for quantitative analysis of the parameters affecting productivity and economics to achieve the overall optimum performance of a horizontal well project. This study shows that production is no longer proportional to the horizontal well length after a critical point. The critical point is calculated as a function of the length of the horizontal production section, flow rate, drawdown pressure, and other parameters. A step-by-step calculation procedure with examples is described with sets of graphical charts developed for illustrating the relationships between the various parameters.
Laboratory-Instrumented Sucker-Rod Pump
Authors: Podio A. L. , Gomez Jaime , Mansure A. J. , Williams Benny , Mahoney Mark
Published: December 2007

Although sucker-rod pumps are installed in nearly 90% of all oil wells and many gas wells (for liquid unloading) in the United States and have been widely used for decades, there are many issues regarding their hydraulic performance that are not well understood. This is caused by the difficulty of obtaining downhole pump-performance data. Many persistent problems in sucker-rod pumping, including partial pump fillage, gas interference, gas locking, fluid pound, sticking valves, rod downstroke compression loading, equipment failure, reduced production, etc., are difficult to diagnose from the surface. Currently, verification of sucker-rod pump problems can only be inferred by removing the pump at great expense. Thus, root-cause analysis depends on guesswork and component analysis. Knowledge of pump characteristics downhole would allow problems to be predicted rather than simply diagnosed after they have persisted long enough to result in failure.

To develop a knowledge base on sucker-rod pumps, a two-fold approach is being pursued: instrumentation of a clear sucker-rod pump in the laboratory, followed by the development of an instrumented downhole pump. The laboratory pump allows the development of diagnostic techniques in which pump performance can be verified visually. The downhole pump will allow testing at field conditions.

A key element to both the laboratory and downhole instrumented pumps is measuring the compression chamber pressure (pressure within the pump barrel). The instrumentation has been designed to collect high-speed (≥100 samples a second) data so that transient behavior (ball chatter, etc.) can be observed. Data is archived while the pump operates under various conditions, from full to pumped off.

This paper presents results of tests with the laboratory pump that have resulted in new insights about pump friction and the techniques developed to measure dynamic and static pump friction. Analyses of the compression-chamber pressure are leading to a better understanding of what happens when both valves are closed and leading to the development of techniques to perform real-time diagnoses that determine fillage and gas locking. The laboratory data showed that compression-chamber data can be insightful in understanding pump conditions.
Numerical Modeling of Aquifer Disposal of CO2
Authors: Pruess Karsten , Xu Tianfu , Apps John , Garcia Julio
Published: December 2007

Disposal of CO2 from stationary sources (fossil-fired power plants) into brackish (saline) aquifers has been suggested as a possible means of reducing emissions of greenhouse gases into the atmosphere. Injection of CO2 into such aquifers would be carried out at supercritical conditions and would give rise to the evolution of a two-phase fluid system, in which most of the injected CO2 will reside in a dense supercritical gas phase, while also dissolving partially into the aqueous phase and reacting with native minerals. This paper presents scoping studies of the amounts of CO2 that can be trapped into the various phases (gas, aqueous, and solid) for a range of conditions that may be encountered in typical disposal aquifers. Our analyses employ a realistic fluid property (PVT) description of brine/CO2 mixtures for supercritical conditions, which takes into account real gas density and viscosity effects for CO2, and includes pressure, temperature, and salinity dependence of CO2 dissolution into the aqueous phase. The fluid property description has been incorporated into a multipurpose reservoir simulator, and has been used to evaluate dynamic effects of CO2 injection into aquifers. A survey of minerals commonly encountered in crustal rocks was made to identify possibilities for chemical sequestration of CO2 through the formation of carbonates of low solubility. We also performed batch reaction modeling of the geochemical evolution of representative aquifer mineralogies. Results indicate that under favorable conditions the amount of CO2 that may be sequestered by precipitation of secondary carbonates is comparable to the amount of CO2 dissolved in pore waters. The accumulation of carbonates in the rock matrix and induced rock mineral alteration caused by the presence of dissolved CO2 lead to a considerable decrease in porosity.
Optimizing the Perforating Strategy in Well Completions To Maximize Productivity
Authors: Underdown D. R. , Jenkins W. H. , Pitts A. , Venkitaraman A. , Li H.
Published: December 2007

The Britannia field is a gas-producing reservoir operated jointly by Chevron and Conoco. Before completion of the wells, the major concern was the optimum underbalance to obtain zero perforation skin during completion. Theoretical models were used to predict the optimum underbalance based on log-derived formation properties. With detailed log permeability data, numerous simulations were carried out to choose the gun, charges, shot density, and perforating strategy for optimum productivity. Different shot densities and charges were used in different sections of the formation based on simulation results, as opposed to choosing perforation parameters based on average well properties.

Experiments were conducted to confirm the theoretical underbalance predictions at high underbalance pressures. Reservoir and outcrop core samples were perforated at simulated downhole conditions in the laboratory at different underbalances based on values obtained from the model. Flow performance evaluation of the perforated reservoir core samples confirmed earlier conclusions on the sensitivity of the formation to aqueous wellbore fluids (brine). An underbalance value of 1,000 psi used in the outcrop sample tests indicated near-zero perforation skin. A perforation strategy for the North Sea field was chosen based on the results from this study. Well performance analyses of 12 of the wells completed indicate low to negative skins. The information is presented in this paper as a case of how to design a good perforating job and also to emphasize the need to study optimum underbalance for gas formations.
The Onset of Instability During Two-Phase Immiscible Displacement in Porous Media
Authors: Peters Ekwere J. , Flock Donald L.
Published: December 2007

This paper presents a dimensionless number and its critical value for predicting the onset of instability during immiscible displacement in porous media. The critical dimensionless number obtained from a stability theory for a cylindrical system successfully predicted the onset of instability in laboratory floods. Therefore, this number can be used to classify the stability of two-phase incompressible displacements in homogeneous porous media.
Successfully Managing Drilling-Fluid Losses in Multiple, Highly Depleted Sands
Authors: Jones J. F. , Taylor G. D. , Barree R. D.
Published: December 2007

Successfully drilling through depleted sands to reach deeper targets often demands a delicate balancing act between maintaining mechanical stability in normal and overpressured shales and controlling fluid losses caused by hydraulic fracturing. A host of considerations go into the planning process, including whether further production from the depleted zones is planned.

Because of the prohibitive cost of a new North Sea well, a stability analysis was performed to determine the feasibility of sidetracking from an existing well and then directionally drilling through two highly depleted sand formations with a single hole section.

The case study presented compares the original mechanicalstability and hydraulic-fracturing estimates with the actual mud weights used to successfully complete this difficult drilling operation. Descriptions of hole instability and fluid losses are presented along with the drilling fluid parameters used to combat them. Methods used for estimating formation pore pressure, in-situ stresses, and formation rock properties are also described. In addition, possible explanations for the differences between the planned and actual stability estimates are explored, with future recommendations for similar operations.