bluuebunny/crossref_metadata_2025 huggingface dataset:
Some Data Processing and Engineering Calculations With Slow to Medium Speed Computers
Authors: Walker John W.
Published: December 2007

The paper describes methods of solving several reservoir engineering and data processing problems using slow to medium speed computing machines. The problems handled are:Solution of the Hurst-van Everdingen material balance equation for which at first only water influx terms and y curves for PVT samples were calculated with the IBM 602A and 604 computers, while later the complete solution of the equation was programmed on the IBM 607 computer. The application of this equation requires computing cumulative water influx volumes at successive dates and matching these figures with the difference between the corresponding cumulative reservoir volumes withdrawn, and the corresponding cumulative expansions of the initial volume of reservoir oil and gas.Vapor-liquid equilibrium flash calculations which are solved rapidly with the IBM 602A or 604. Auxiliary calculations were made to convert the results into usable engineering quantities.Statistical analyses, performed on core data for several fields, providing a better understanding of the reservoir characteristics.Preparation of the annual (statistical) reserve report. This report starts with the previous year's figures for the gross and net reserves, cumulative and ultimate production, separated into oil, condensate and total liquid figures by leases. Revisions to reserves, classified according to 10 categories such as discoveries, new zones, extensions, etc. are added to the opening reserves and ultimate production figures, while the yearly production figures are subtracted from the revised figures and added to the cumulative figure. Statistical data concerning leasehold titles and ownership fractions, well counts, etc. are recorded. All figures are summarized according to zones, fields, leases, divisions and areas.Miscellaneous uses of analytical procedures for production accounting figures, such as oil pipe line runs, etc. provided better control of production operations.

Introduction

The annual reserve report is a statistical statement of gross and net reserves, including revisions of reserve estimates and production during the year. The responsibility for preparing this report was assigned to reservoir engineers and by 1952 the report required considerable engineering, clerical and stenographic time.
Accuracy Prediction for Directional Measurement While Drilling
Authors: Williamson H. S.
Published: December 2007

In this paper a new method for predicting wellbore position uncertainty which responds to the current needs of the industry is described. An error model applicable to a basic directional measurement while drilling (MWD) service is presented and used for illustration. As far as possible within the limitations of space, the paper is a self-contained reference work, including all the necessary information to develop and test a software implementation of the method. The paper is the product of a collaboration between the many companies and individuals cited in the text.
Enhanced Interpretation of Temperature Surveys Taken During Injection or Production
Authors: Murphy Hugh D.
Published: December 2007

Temperature surveys run during well injection or production can reveal not only intake or production intervals but also the rate of flow. From previous work, the flowrate analysis is based on the "subtangent" or "delta function," which is simply the change in temperature induced by the flow divided by the thermal gradient. This paper investigates accuracy and limitations. of this simplified analysis, and provides design guides for selecting conditions that optimize interpretation. Methods for distinguishing flow-rate changes from changes in formation properties or well radius also are presented.

Introduction

Diagnostic temperature surveys in wells are at least 60 years old. The earliest use of temperature measurements was primarily for geophysical and geological purposes. For example, determining geothermal gradients, required for regional heat flow studies, was reported by van Orstrand1 and Heald.2 Lithological variations were identified by local departures from the prevailing geothermal profile that were caused by thermal property variations of the formations.3 In the mid-1930's attention turned toward using temperature surveys to diagnose well completion and production problems.4 Deussen and Guyod5 described it technique for determining the position of cement emplacement that relied on the temperature increase caused by heat of hydration. Lost circulation zones were identified as warm or cool temperature anomalies, depending on whether the drilling fluid was hotter or colder than the thieving formation.6 Potential gas production zones were inferred from local anomalies caused by the cooling effect of the depressurized gas as it entered the well.6

More recently attention has focused on the use of temperature surveys to infer flow rate profiles within wells. The methods can be applied to either injection or production wells. For example, in cased wells positions and magnitudes of casing leaks can be identified. In openhole sections the fluid intake or production strata can be located, and the injectivity or productivity of formations can be profiled. In this manner temperature surveys are similar to flowmeter. surveys (e.g., a spinner survey) except that unlike flowmeter surveys temperature surveys can detect flows behind casing7 - e.g., water aquifer flows - and are particularly useful for locating hydraulic fractures.8
Improving the Working Environment and Drilling Economics Through Better Understanding of Oil-Based Drilling Fluid Chemistry
Authors: James R. W. , Schei T. , Navestad P. , Geddes T. A. , Nelson M. G. , Webster D.
Published: December 2007

The relationships between oil-based drilling fluid composition and the associated vapors have been quantified. The study documents the long- and short-term changes in base oil selection and fluid compositions. The study is based on the generation and assessment of data collected from the vapor emissions of oil-based drilling fluids with varying compositions and at a range of temperatures.

The purpose of the study was to enable a better understanding of the potential working environment hazards when using mineral oil-based drilling fluids. One result of this understanding is that new rig construction designs and older rig upgrades can be performed more informatively. This will reduce the repetition of continual modification costs.
Pore-Network Model of Flow in Gas/Condensate Reservoirs
Authors: Wang Xiuli , Mohanty K. K.
Published: December 2007

A pore-scale network model is presented here for gas-condensate flow. Porous media are modeled by networks of pore bodies interconnected by pore throats. Pore-level laws are identified from previously published micromodel and multiphase pipe flow experiments. The condensate can flow due to three mechanisms: pressure gradient within the sample-spanning condensate phase, movement of condensate slugs, and condensate droplets carried by the gas flow. Inertial effects are important for high rate gas flows. The relative permeabilities and non-Darcy coefficients have been computed for the low capillary number and low condensate saturation-high pressure gradient flow regimes.
Representing Steam Processes With Vacuum Models
Authors: Stegemeier G. L. , Laumbach D. D. , Volek C. W.
Published: December 2007

Scaled models of steam processes have contributed significantly to the design and implementation of many field projects. These models provide a means of answering pertinent questions, including the effect of (1) injection rate, (2) production pressure, (3) completion interval, (4) pattern size and type, (5) aquifers, (6) heterogeneities, and (7) steam quality.

Parameters are presented for scaling up physical-model results to full scale and for relating one oil field to another. These relationships are generated by casting the governing equations in dimensionless form. A set of similarity parameters then are determined by inspectional analysis. In physical models, unfortunately, it is not possible to match all similarity parameters. Consequently, based on engineering judgment, a set containing a reduced number of parameters, called scaling parameters, is generated that generally can be matched between scaled model and field prototype.

Techniques to implement this scaling are discussed, including a description of the laboratory models, typical materials, and procedures for conducting the experiments. Results of model studies for Mt. Poso and Midway Sunset prototypes are presented.
Semi-Analytical Model for Thermal Effect on Gas Well Pressure-Buildup Tests
Authors: Fan L. , Lee W. J. , Spivey J. P.
Published: December 2007

This paper presents a semi-analytical wellbore/reservoir model1 that can describe general wellbore effects, especially the thermal effect, on high-temperature gas well pressure-buildup tests. A numerical simulator has been developed from the model. Using different combinations of wellbore and reservoir parameters, the simulator generated curve shapes that differed with wellbore thermal effects. Many of the curve shapes have been observed in the field.2,3 Using the results from this paper, engineers can distinguish between general wellbore effects and reservoir behavior in the pressure data, which will make the interpretation more accurate. Also, with the help of the simulator developed from the model, engineers can effectively design gas well pressure-buildup tests by running the simulator to determine the minimum time required to obtain the data not distorted by the wellbore effects.4

The governing equations of the wellbore model are based on mass, momentum, and energy balances for single-phase gas in one-dimensional space. The gas pressure/volume/temperature correlation was also used. Different flow regimes (laminar, transitional, and turbulent) inside the wellbore are modeled for calculating the friction factor. As one boundary condition, a simple analytical reservoir model was connected to the wellbore model at the bottomhole using Duhamel's principle. Heat-loss effects account for forced-convectional heat transfer inside the tubing, heat conduction between tubing and formation, natural convection and radiation heat transfer of annular fluid, and transient heat flow in the formation. Pressure, temperature, velocity, and gas properties inside the wellbore can be predicted at any depth during an entire pressure-buildup test. Variable wellbore storage, momentum, and thermal effects can be simulated.
Estimation of Hydrocarbon Viscosity With Multiple-†e, Dual-†wMRIL Logs
Authors: Chen Songhua , Georgi D. T. , Olima Oscar , Gamin Hector , Minetto J. C.
Published: December 2007

We report a case study of using nuclear magnetic resonance (NMR) multiple-te, dual wait-time (tw) log acquisitions for quantitative characterization of San Jorge Basin reservoir oil viscosity. Previously, dual-tw logs have been used to discern gas and oil from water, while dual-te logs have been used as a qualitative light oil indicator. Although theoretically simple, quantitative determination of viscosity from dual-te logs is complicated by several factors, including poor signal-to-noise ratio, difficulties in separating oil from water, and the uncertainty of internal gradient strength. In the present study, multiple-te acquisitions of dual-tw logs were used to isolate the oil from the water signal. The values of viscosity of the reservoir fluids can be estimated from either intrinsic T2 or T1. In estimation of the apparent T2, we used a model that does not explicitly require knowledge of the internal gradient, thereby minimizing the effects arising from the uncertainty of the internal and tool gradient strengths. Because Tj and intrinsic T2 are estimated independently, the degree of agreement between the two values provides an indication of the reliability of the two estimates. The main example in the study of four pay zones was thought to contain viscous oil. However, our analysis indicated that the viscosity values of the oil are less than 5 cP. The predictions have been substantiated by production of light hydrocarbons from the three zones that have been perforated. Further, a good agreement is obtained for the viscosity estimates based on NMR log data and laboratory pressure/volume/temperature (PVT) analysis.
Measurements of Relative Permeabilities for Calculating Gas-Condensate Well Deliverability
Authors: Mott R. E. , Cable A. S. , Spearing M. C.
Published: December 2007

Well deliverability in many gas-condensate reservoirs is reduced by condensate banking when the bottomhole pressure falls below the dewpoint, although the impact of condensate banking may be reduced due to improved mobility at high capillary number in the near-well region.

This paper presents the results of relative permeability measurements on a sandstone core from a North Sea gas-condensate reservoir, at velocities that are typical of the near-well region. The results show a clear increase in mobility with capillary number, and the paper describes how the data can be modeled with empirical correlations which can be used in reservoir simulators.
A Method of Analyzing Performance of Gravel-Pack Completions in Seria Field, Brunei
Authors: Jones R.W. , Thorp G.
Published: December 2007

A method of evaluating gravel-pack completions has been developed that allows the use of small samples of observed data with large variance to be checked against theoretically derived values-in this case, the normalized productivity indices. The results give insight into the mechanics of productivity indices. The results give insight into the mechanics of impairment and lend support to previously suspected causes of impairment.

Introduction

Brunei Shell Petroleum (BSP) Co. Ltd.'s Seria field produces from shallow, unconsolidated, depleted produces from shallow, unconsolidated, depleted sands. The majority of wells require sand control during their production lifetime, and over the years many gravel packs, both openhole and inside packs, have been placed. The productivities achieved by the various gravel-pack repair techniques have been difficult to analyze due to the few reliable data points and wide range of values.

Therefore, a statistical test was used to compare actual productivity indices (PI's) before and after gravel packing with theoretically derived PI's. The effects on productivity of different types of gravel packing and different gravel sizes also were compared. packing and different gravel sizes also were compared.To do tills it was necessary to establish theoretical values for the specific PI's (RB/D/psi/ft) of the various pack configurations using Seria reservoir data and completion sizes.

The changes in well productivity as a result of gravel packing were calculated theoretically for the various gravel-pack types and placement methods by considering the individual pressure drops through the sequential resistances to flow imposed by gravel and liner and by considering these resistances as apparent skin factors in the flow equation.

The equations were developed using typical Seria field reservoir data and completion sizes.

Gravel-Pack Types

There are two basic types of gravel packs used in BSFs Seria field: openhole gravel packs (OHGP) and inside gravel packs (IGP).

Openhole Gravel Packs

An OHGP consists of a slotted liner or wire-wrapped screen in an open hole, packed around with gravel. The openhole section normally is underreamed to increase the effective wellbore radius and pack thickness. This is achieved simply in a new completion; in an existing completion this requires milling a window in the casing, sidetracking, underreaming, and then gravel packing. This is referred to as a sidetracked underreamed gravel pack (STUGP). pack (STUGP).OHGP's allow completions with little apparent PI impairment and not too severe PI decline with continuing production. It will be shown later that in practice severe pack impairment does occur but practice severe pack impairment does occur but largely is offset by the increase in effective wellbore radius as a result of the underreaming.

JPT

P. 496
Reservoir Characterization of Ekofisk Field: A Giant, Fractured Chalk Reservoir in the Norwegian North Sea-History Match
Authors: Agarwal B. , Hermansen H. , Sylte J. E. , Thomas L. K.
Published: December 2007

The Ekofisk reservoir is a high porosity, low matrix permeability naturally fractured chalk. Fluid flow is largely governed by the distribution, orientation, and interconnectivity of the natural fracture system associated with complex structure and reservoir distribution. Because of the impact heterogeneity has on preferential fluid-flow direction, significant attention was given to capturing as much of the intrinsic heterogeneity as possible, both laterally and vertically, in the new three-dimensionally geological model. A non-uniform simulation mesh was defined for the fluid-flow model with a grid size of 450 ft × 450 ft in the crestal area of the field and increasing towards the flanks. A flow-based upscaling technique was then applied to preserve the heterogeneity from the geological to the fluid-flow model. Because of the complexity of the Ekofisk field, with its numerous faults and fracture networks, anisotropy was one of the primary attributes calibrated to achieve an individual well and field history match. However, faults and fault sealing factors, vertical permeability, pseudorelative permeability curves, bubblepoint pressure correlations, local permeability, and rock compressibility were also key parameters in the history match, and are presented in this paper. A brief discussion on the preliminary implementation of water-induced compaction is included.
Chemical Transport in Porous Media With Dispersion and Rate-Controlled Adsorption
Authors: Satter A. , Shum Y. M. , Adams W. T. , Davis L. A.
Published: December 2007

Because of the importance of chemical flooding operations, the mechanisms of chemical dispersion and adsorption in porous media are of increasing interest to the petroleum industry. This paper presents a mathematical model for simulating presents a mathematical model for simulating chemical transport phenomena in porous rocks; these phenomena include dispersion and either Langmuir phenomena include dispersion and either Langmuir equilibrium or rate-controlled adsorption.

The accuracy of this numerical model was verified by comparing the calculated results with those obtained by analytical solutions for a number of limiting cases. The effects of dimensionless dispersion, adsorptive capacity, flow rate, and kinetic rate groups controlling dispersion/adsorption mechanisms were investigated. The utility of the model was demonstrated further by matching experimental results. When adsorption of a chemical is rate-controlled or time-dependent, core flood data obtained at times much shorter than reservoir residence times can lead to a serious underestimation of chemical requirements for the field projects.
Computer Design of Dense-Phase Pipelines
Authors: Gregory G.A. , Aziz K. , Moore R.G.
Published: December 2007

This paper demonstrates the importance of performing simultaneous temperature and pressure profile calculations when designing pipelines for single dense-phase fluids. The sensitivity of the pressure and temperature profiles to design parameters is examined and discussed in detail. profiles to design parameters is examined and discussed in detail. Introduction

The pressure and temperature changes for single-phase flow along a pipeline are described by the following differential equations:

dp p dv g dZ 2fv2p--- + -- v ---- +p --- ----- + ------- = 0,.......(1)dL gc dL gc dL gcd

dh 1 dv g dZ 1 dQ---- +--- v --- + --- ---- + --- --- = 0,......(2)dL gc dL gc dL w dL

where the following functional relationships must be specified.

p =f(p, T)......................................(3)h =f(p, T)......................................(4)=f(p, T)......................................(5)f =f(N Re, k/d).................................(6) wheredvpN Re = ----.......................................(7)

The expressions for p, h, and may be either analytical or graphical, and their complexity depends on the type of fluid being considered. Many different expressions for the friction factor, f, are also available; some are general and some are for specific pipeline and fluid systems.

For hand calculations, Eqs. 1 and 2 must be integrated over the length of the pipeline to obtain analytical expressions for pressure and temperature as functions of length, flow rate, fluid properties, and pipe-to-sod interactions. This poses problems for the general case becausethe equations are nonlinear and coupled,the fluid properties depend on pressure and temperature in a complex manner, andthe friction factor is a nonlinear function of viscosity, density, and velocity.

Thus, to obtain the analytical expressions, various simplifying assumptions must be made. This procedure has resulted in many design equations that apply to particular systems and are useful when the inherent assumptions are valid. However, in some cases, particularly when dealing with a fluid near the critical region particularly when dealing with a fluid near the critical region (i.e., dense fluid state), variations in the physical and thermodynamic properties are rather complex and no available integrated form of the equations can be used safely.

If adequate information is available about the relationships expressed by Eqs. 3 through 6, Eqs. 1 and 2 can be integrated numerically to any desired accuracy without making any simplifying assumptions. Clearly, this approach is only practical when a digital computer is available, but it is completely general and may be followed for any single-phase flow in a pipe (gas, liquid, or dense phase). This procedure is the basis of the computer program used to perform all calculations discussed later. Extension of the approach to multiphase gas-liquid flow in pipes and structure of the program are discussed elsewhere.

P. 40
Development of a New, Compact Electrostatic Coalescer Concept
Authors: Urdahl O. , Nordstad K. , Berry P. , Wayth N. , Williams T. , Bailey A. , Thew M.
Published: December 2007

The demand for more cost-effective field developments has led to a substantial focus on separation equipment that reduces weight and deck space. Of particular concern are field developments with subsea production templates and multiphase transportation to existing field installations. Additionally, environmental aspects concerning the use of large amounts of chemical demulsifiers are crucial these days.

This paper presents a new compact electrostatic coalescer (CEC) that has the capability to reduce both weight and size, and to eliminate the use of chemical demulsifiers, in some cases.

The basic principle of Performance of the laboratory version of the CEC is discussed with respect to emulsion properties, flow rate, applied voltage, and residence time in the electric field. Performance is quantified using both a laser-particle and droplet-size analyzer and a Hamamatsu image-analysis system. Some results from a prototype test on live crude are also given.
Laboratory Monitoring of Surfactant Imbibition With Computerized Tomography
Authors: Chen H. L. , Lucas L. R. , Nogaret L. A. D. , Yang H. D. , Kenyon D. E.
Published: December 2007

Oil production from fractured reservoirs can occur by spontaneous water imbibition and oil expulsion from the matrix into the fracture network. Injection of dilute surfactant can recover additional oil by lowering oil/water interfacial tension (IFT) or altering rock wettability, thereby enhancing countercurrent movement and accelerating gravity segregation. Modeling of such recovery mechanisms requires knowledge of temporal and spatial fluid distribution within porous media. In this study, dilute surfactant imbibition tests performed for vertically oriented carbonate cores of the Yates field were found to produce additional oil over brine imbibition. Computerized tomography (CT) scans were acquired at times during the imbibition process to quantify spatial fluid movement and saturation distribution, and CT results were in reasonable agreement with material-balance information. Imbibition and CT-scan results suggest that capillary force and IFT gradient (Marangoni effect) expedited countercurrent movement in the radial direction within a short period, whereas vertical gravity segregation was responsible for a late-time ultimate recovery. Wettability indices, determined by the U.S. Bureau of Mines (USBM) centrifuge method, show that dilute surfactants have shifted the wetting characteristic of the Yates rocks toward less oil-wet. A numerical model was developed to simulate the surfactant imbibition experiments. A reasonable agreement between simulated and experimental results was achieved with surfactant diffusion and transitioning of relative permeability and capillary pressure data as a function of IFT and surfactant adsorption.
Mars Debottlenecking Project
Authors: Curole M. A. , Turley A. J.
Published: December 2007

The Mars installation consists of a four-block unit with a tension leg platform (TLP) installed in Mississippi Canyon Block 807. The discovery well was drilled in 1989. Development studies were conducted from 1990 through 1992 with project-fabrication funding occurring in the fall of 1993. A 24-well dual-casing-riser TLP in 2,933 ft of water was approved. The facility was designed originally to process 100,000 B/D oil and 110 MMscf/D gas. Maximum individual well rates were estimated at 11,000 B/D oil. During the fabrication phase of the project in 1995, it became clear that completion technology advances had increased individual well production potential far beyond the 11,000-B/D-oil benchmark, and the ultimate TLP production potential would exceed the topsides nameplate capacity. A study was undertaken to debottleneck the topsides to handle unconstrained production rates. The study evaluated all phases of the production facility impacted by increased production. This paper presents evaluated phases of the production facility debottleneck, summarizes modifications to the facilities at the TLP integration site, and reviews the use of several new and innovative technologies. Facilities systems debottlenecked included high-rate production flowlines, oil treating, compression units, dry-oil sales pumps, utility, flare, and gas dehydration.
Enhanced 2D Proppant-Transport Simulation: The Key To Understanding Proppant Flowback and Post-Frac Productivity
Authors: Smith M. B. , Bale A. , Britt L. K. , Hainey B. W. , Klein H. K.
Published: December 2007

It has been assumed that along with fluid viscosity and pump rate, gravity dominates final proppant placement in hydraulic fractures. Results here, based on detailed multiphase-flow modeling, show that other factors such as slurry rheology (effect of adding proppant on slurry viscosity), fluid loss and layered fluid loss, and vertical fracture-width variations often are more important than gravity in controlling placement.

The goal of a hydraulic-fracture treatment is to create a large flow area exposed to the formation and connected to the wellbore along a conductive path. The only goal of hydraulic-fracture models is to predict this final proppant placement accurately. Most theoretical, modeling, and experimental efforts in this area have focused historically on understanding and predicting only gravity effects on proppant placement.

However, for proppant-laden, viscous fluid or slurry flowing along a fracture, other forces are always more important than gravity, and can easily cause proppant to move upwards, both during pumping and fracture closure.

A differential-fracture closure occurs when a fracture growing vertically penetrates zones with higher or lower closure stress. After shut-in, higher stress zones "close first." This forces any proppant-laden slurry covering these zones (at shut-in) to migrate to low stress zones where fracture width is greater, and can easily lead to "upward" proppant movement as fracture-closure stress generally decreases with depth. After shut-in of a propped fracture treatment all fluid must leak off into permeable formations penetrated by the fracture. Until closure, viscous fluid continues to transport proppant (possibly upward) toward fluid-loss layers, often corresponding to "pay." As proppant is introduced to fluid, the resulting slurry has a higher density and tries to move downward. However, solids also act to increase viscosity, and more viscous slurry prefers the wide middle of a fracture. This serves to keep proppant near the middle of the fracture, often in the pay zone.

This paper discusses the combined effect of these forces on proppant placement in a context of post-frac analysis of several field treatments. Analysis used a fracture model including "rigorous," numerical, 2D material transport, and the often-unexpected results are compared with supporting evidence from post-frac well performance. In many instances, the combined effect of proppant-placement forces is beneficial, with more proppant placed across the pay than suggested by simple models. In other cases, post-shut-in proppant redistribution can (and did) cause catastrophic job failure.
Computer Simulations of Proppant Transport in a Hydraulic Fracture
Authors: Mobbs A. T. , Hammond P. S.
Published: December 2007

Equations of motion of a slurry in a narrow slot, such as a hydraulic fracture, are presented and solved numerically to obtain an estimate of the amount of gravity-driven vertical motion of proppant that can occur within a fracture during placement.

Two types of gravity-driven motion are studied: settling of heavy-proppant particles; and convective proppant transport, which refers to the motion driven by large-scale density differences between regions of different proppant concentration.

Computer simulations are performed using realistic parameter values. In particular, the vertical motion of proppant in a slurry in which proppant particles are uniformly distributed across the fracture width (referred to as homogeneous flow) is compared with that in a slurry in which some unspecified, but rapid, process has caused all proppant to migrate across the fracture width into a close-packed sheet at the fracture center (referred to as sheet flow).

In addition to considering a constant channel width, we also investigate the effects of an elliptic-fracture cross section on proppant placement. This fracture shape is predicted by idealized fracture propagation models such as the Perkins-Kerns-Nordgren (PKN) model.

Main conclusions are that during placement:

Proppant settling and convection can occur under practical conditions; Convection rates are slightly greater in sheet flow than in homogeneous flow, and settling is greatly enhanced in sheet flow. Overall, settling in sheet flow gives the worst vertical motion of proppant. Settling and convection in homogeneous flow cause no problems under conditions considered in this paper; In elliptic fractures, heavy, proppant-laden slurry can override earlier-pumped lighter pad (zero solids) under most fracturing conditions.
What Causes Bumps in Minifrac Pressure Declines?
Authors: Shaoul Josef R. , Pater C. J. (Hans) de , Roodhart Leo P. , Meijers Hans C.
Published: December 2007

In many cases, a momentary increase is observed in wellhead pressure after pumping a minifrac, which could compromise reliable interpretation of the pressure decline. We found that the cause of the pressure bump was severe underdisplacement of crosslinked gel. The crosslinked gel at the bottom of the wellbore may create a plug, which effectively makes the wellbore a closed vessel disconnected from the fracture.

To avoid this bump, it is recommended to displace the crosslinked gel to the perforations or even slightly overdisplace. If this is impossible, the simplest correction for the pressure bump is to use the initial pressure decline before the bump, and shift the final decline after the bump downwards by the magnitude of the bump.
Progress Towards Zero-Based Hookup
Authors: Hume Ian
Published: December 2007

This paper charts the step change continuous improvements achieved in U.K. completion system (CS) hookups from 1992 through 1998. Fig. 1 shows that improvements to this process have caused the man-hours/tonne required to hook up and commission (HUC) large offshore installations (greater than 20,000-tonne top-sides) to fall from an industry average of 75 man-hours/tonne to less than 10 man-hours/tonne.

The change process has been complex. It was necessary not only to challenge technical sacred cows but also philosophical, cultural, and organizational core beliefs prevalent in our industry during this period.

The story is not complete yet. There are still significant activity level reductions to be delivered, some of which have been targeted already. We have no doubt that we or others will deliver yet more.
A New Multiband Generation of NMR Logging Tools
Authors: Prammer M. G. , Bouton J. , Drack E. D. , Miller M. N. , Chandler R. N.
Published: December 2007

This paper describes the hardware and operation of a new generation of nuclear magnetic resonance (NMR) logging tools. In the past, NMR required the logging engineer to consider the T1 relaxation times of the reservoir fluids likely to be encountered. Actual, or simply assumed, long T1's translated into slow logging speeds. The new tool generation overcomes this limitation. The key feature is that nine sensitive volumes are polarized in parallel and are read out in rapid sequence. A new sonde design speeds up the polarization process by a factor of 2. Each volume contributes equally to the result and can support identical measurements for rapid stacking and fast logging, and each can be used for individual, simultaneous measurements.

Laboratory data and field-test results are presented to demonstrate both the relative simplicity of operation and the improvement in data quality. Logging speeds typically can be upgraded by a factor of 4, while data for total porosity determination and fluid typing are acquired in a single logging pass.
Experiments and Modeling of High-Velocity Pressure Loss in Sandstone Fractures
Authors: Skjetne Erik , Kløv Trygve , Gudmundsson J. S.
Published: December 2007

High-velocity pressure loss in Bentheimer sandstone fractures of varying fracture widths was studied. Direct measurements of the roughness showed that the fractures are self-affine. The new results support a rough fracture high-velocity pressure-loss model. The high-velocity pressure loss was described by a Forchheimer equation with a dominating square term. The square term is a power law in fracture width, and the power is given by a roughness exponent. For low velocities, the pressure loss was not described by the Forchheimer equation. In agreement with theory, a weak-inertia-flow regime exists that separates the Darcy-flow regime from the Forchheimer-flow regime. An expression for the incremental high-velocity skin of a pinched-out hydraulic fracture was derived. Asymptotically for small fracture widths the skin is a power law in fracture width.
The Benefit of Local Saturation Measurements in Relative Permeability Estimation From Centrifuge Experiments
Authors: App J. F. , Mohanty K. K.
Published: December 2007

The standard method for estimating relative permeabilities from centrifuge experiments is to match the production data. This study examines under what conditions local saturation measurements (in addition to production data) can improve the estimation of wetting-and nonwetting-phase relative permeabilities. Synthetic experimental data were obtained through simulation. Three distinct sets of wetting- and nonwetting-phase relative permeability curves at low and high mobility ratios were used to construct the experimental data. The relative permeabilities were then history matched through nonlinear regression using either local saturation and production measurements or only production measurements. Local saturation in conjunction with production measurements can improve the estimation of relative permeabilities from centrifuge experiments. The most significant improvement is in the prediction of the wetting-phase relative permeability at low mobility ratios (e.g., less than 5). For gas/oil systems (with high mobility ratio), the wetting-phase (oil) relative permeability was accurately estimated in all cases using an initial guess based on Hagoort's method with or without local saturation data. Prediction of the nonwetting-phase relative permeability is still difficult under some conditions.
Determination of Original Gas in Place in Ballycotton, Offshore Ireland
Authors: Chu Wei-Chun , Fleming C. H. , Carroll K. M.
Published: December 2007

Early, accurate determination of original gas in place (OGIP) is highly desirable for planning the future of a gas field. This paper presents a case history of an offshore gas field, using a recently developed pressure-rate-time analysis technique to illustrate the effectiveness of the method. In addition, this paper demonstrates the great benefit of permanently installed pressure gauges in obtaining consistent pressure and flow-rate data for the effective use of the technique for subsea completed wells.
Experimental Modeling of the SAGD Process - Enhancing SAGD Performance with Periodic Stimulation of the Horizontal Producer
Authors: Sasaki K. , Akibayashi S. , Yazawa N. , Doan Q. T. , Ali S. M. Farouq
Published: December 2007

Experiments on initial stages of the steam-assisted gravity drainage (SAGD) process were carried out, using two-dimensional (2D) scaled reservoir models, to investigate production process and performance. Expansion of the initial steam chamber, its shape and area, and its temperature distributions were visualized with video and thermal-video pictures. The relationship between isotherms and steam-chamber interface was investigated to study the drainage mechanism. Temperature at the expanding steam-chamber interface was observed to remain nearly constant at close to 80°C. The effect of vertical spacing between the two horizontal wells on oil recovery was also investigated. For the Conventional SAGD case, oil production rate increased with increasing vertical spacing between the wells; however, the lead time for the gravity drainage to initiate oil production became longer. The results suggest that vertical spacing between the wells can be used as a governing factor to evaluate production rate and lead time in the initial stage of the SAGD process. Based on these experimental results, the SAGD process was modified; the lower production well was intermittently stimulated by steam injection, in conjunction with continuous steam injection in the upper horizontal injector. With the modified process (named SAGD-ISSLW), the time to generate near-breakthrough conditions between two wells was shortened, and oil production was enhanced at the rising chamber stage compared with that of the Conventional SAGD process.
A New Methodology for the Optimization of the Placement of Downhole Production-Monitoring Sensors
Authors: Nœvdal G. , Vefring E. , Berg A. , Mannseth T. , Nordtvedt J. E.
Published: December 2007

A new methodology for designing the placement of production-well-monitoring sensors is presented. With a well-flow simulator, we estimate the inflow profile of a production well and solve the inverse problem associated with the mathematical model for fluid flow in the well. The accuracy in the estimated inflow profiles using different types and placements of sensors can be computed, and an efficient way to search for an instrumentation layout is presented.
Particle Transport Through Perforations
Authors: Gruesbeck C. , Collins R. E.
Published: December 2007

This paper describes a new procedure for determining particle-transport efficiency through perforations. Transport efficiency is the mass fraction of particles that are transported through the perforations relative to the total mass of particles injected. Our conclusions are based on laboratory studies of the transport of solid particles carried through perforations by different fluids having a wide range of physical properties. Prediction of particle-transport efficiencies based on theoretical considerations described in this paper gives an accurate representation of experimental results.
Near-Wellbore Halo Effect Resulting From Tip-Screenout Fracturing: Direct Measurement and Implication for Sand Control
Authors: Upchurch Eric R.
Published: December 2007

The near-wellbore geometries of four fracture stimulations are evaluated to determine if fracturing soft, unconsolidated formations can result in placing proppant in a concentric halo around the casing, in addition to placing proppant in the fracture. Whether or not the "halo" exists impacts whether or not fracture stimulating is a viable means of sand control in unconsolidated formations.

This paper presents the findings of an investigation to determine whether a near-wellbore halo is generated during the process of fracture stimulating a well in a soft, unconsolidated formation. The investigation delves into whether net-pressure generation has any effect on the halo's formation and, finally, whether the halo could be used by petroleum operators as an inexpensive way to control formation sand production.

Results from four fracture stimulations in perfectly vertical wells are the primary data used in this investigation. In each case, all necessary steps were taken to ensure that collected data would show conclusively whether or not the halo occurred and, more qualitatively, to what extent a significant net-pressure increase resulting from a tip screenout (TSO) affected the halo's formation. All data presented here resulted from direct downhole measurements, either by bottomhole pressure gauges or by specialized azimuthal gamma ray (GR) logging tools that can directionally measure GR intensity.

To date, the possible existence and benefit of the halo has been a topic of conjecture. This study represents the first attempt at directly confirming the existence and extent of the halo under actual downhole conditions.
Digital Computer Programming for Automatic Analysis of Well Logs
Authors: Southwick S.H. , Adair T.W.
Published: December 2007

Introduction

Improvements in well-logging tools and the introduction of new ones, together with the development of improved interpretive techniques, have greatly increased the utility of logs during the last 10 years. Instead of serving primarily for the correlation of strata, logs are now used to indicate porosity and fluid content of subsurface formations. Under favorable conditions, oil and gas saturation in subsurface reservoirs may be calculated with reliability from log data.

One log interpretation method which gives useful results from many logging programs is the resistivity index method. In this method, a resistivity ratio is computed for each porous zone of interest penetrated by a well. The higher the ratio, or index, for a particular zone in the well, the higher is the probability the zone contains oil or gas. Experience gained with the RI method has shown that selection of zones to be analyzed should not be limited to those likely to contain oil or gas. Zones thought to contain only water should also be selected for analysis. In fact, to obtain the maximum, most reliable information, a resistivity index should be computed for every porous zone in a well. Unfortunately, many hours of concentrated effort by an experienced interpreter may be required to compute resistivity indices in one well which contains numerous porous zones. Hence, it has been impractical to make calculations for all porous zones in all wells. The speed and flexibility of digital computers offer a solution to the problems of computing every porous zone and making rapid use of all available logging data. Freed from the tedium of repetitious computation, the geologist or engineer could function most efficiently by working with the computer results, combining his experience with results from computer calculations to arrive at decisions. To develop a system for analysis of well logs with a digital computer, three steps are necessary. First, the log information must be in computer language; that is, digital form. Second, computer programs must be perfected for the interpretive methods applicable to the various logging systems so that the computer completes the sequence of operations without interruption. Finally, the computer results must be tested or confirmed by comparison with manual interpretation. Step 1, the digitization of log data, both in the laboratory and at the well site, is being investigated by several companies. One machine has been developed to read and digitize logs from ordinary paper prints by a completely automatic procedure. At the present time, however, the only commercial digitization of log data is from ordinary paper prints by semi-automatic processes. Several companies offer this type of service; the charge is in the range of $0.005/datum point, or about $25/1,000 ft. (five curves on a foot-by-foot basis). With advances in technology and an increase in demand, it is hoped that this cost can be reduced substantially.

JPT

P. 35ˆ
Advances in Tightly Coupled Reservoir/ Wellbore/Surface-Network Simulation
Authors: Zapata V. J. , Brummett W. M. , Osborne M. E. , Van Nispen D. J.
Published: December 2007

One of the most perplexing and difficult challenges in the industry is deciding how to develop a new oil or gas field. It is necessary to estimate recoverable reserves, design the most efficient exploitation strategy, decide where and when to drill wells and install surface facilities, and predict the rate of production. This requires a clear understanding of energy distribution and fluid movements throughout the entire system, under any given operational scenario or market-demand situation.

Even after a reservoir-development plan is selected, there are many possible facility designs, each with different investment and operating costs. An important, but not always considered, fact is that each facility scheme could result in different future production rates owing to various types, sizes, and configurations of fluid-flow facilities.

Selecting the best design for the asset requires the most accurate production forecasts possible over the forecast life cycle. No other single technology has the ability to provide this insight, as well as tightly coupled reservoir and facility simulation, because it combines all pertinent geological and engineering data into a single, comprehensive, dynamic model of the entire oilfield flow system. An integrated oilfield simulation system accounts for all dynamic flow effects and provides a test environment for quickly and accurately comparing alternative designs.

This paper provides a brief background of this technology and gives a review of a major development project where it is currently being applied. Finally, we describe some recent significant advances in the technology that make it more stable, accurate, and rigorous.