bluuebunny/crossref_metadata_2025 huggingface dataset:
Subsea TFL Systems - A Technology Update
Authors: Arendt H. , Brands K.
Published: December 2007

This paper presents and analyzes equipment development and testing, completion procedures, and maintenance operations using through-flowline (TFL) methods on five subsea wells in 100 to 200 ft (30.5 to 61 m) of water offshore Brunei. These wells, installed in 1974-76, presently are operated by Brunei Shell Petroleum and include both single-and dual-string (multizone) completions.

Introduction

In the early 1970's, Shell Internationale Petroleum Mij. (SIPM) undertook a series of studies aimed at the development of systems for producing deepwater oilfields beyond the continental shelf. An important building block in deepwater production systems would be the underwater completed (UWC) well. A principal objective was that the UWC wells would be drilled, completed, produced, and serviced using remote control and servicing techniques. Downhole servicing of the well would be done by pumpdown TFL techniques.

Single-Zone Well

In 1971 it was envisaged that the UWC wells would have to be large producers for an economical deepwater field development. The terms of reference established for a diverless deepwater subsea completion resulted in these basic requirements and assumptions:the well must be a prolific producer of 5,000 to 10,000 B/D (794.9 to 1589.8 m3/d);no artificial lift by gas lift would be needed;sand production would not be present;completion would be as simple as possible, preferably with a single production string probably 4 1/2 in. (114.3 mm) OD; androutine well servicing by TFL.

It was decided to install a pilot UWC (Fairley 16) offshore Brunei (Borneo) in relatively shallow water, permitting easy intervention by divers if necessary. For this purpose a project team was set up in Brunei. Since at that time TFL tools and ancillary equipment had been well-developed only for 2 3/8-in. (60.3-mm) tubing, SIPM approached Otis Engineering Corp. in Oct. 1971 to set up a program for developing and testing TFL capability in the larger tubing size [4-in. (102-mm) nominal size tools].Subsequently Otis designed and constructed the TFL tool string and service tools, a surface-controlled subsurface safety valve suitable for TFL, a Sliding Side-Door (SSD), and a standing valve. The equipment was tested in the Otis test well in Dallas from Aug. to Oct. 1972. A number of modifications were made to the equipment. It became apparent that the "reach rod" approach using conventional sucker rods led to unacceptable friction resistance in the TFL loops. ("Reach rod" refers to an operation whereby a flow control may be installed in a nipple below the TFL circulation point by using rods or bars to span the distance between the flow control running tool and the TFL piston units, which must remain above the circulating point.) To counter this friction, knuckled spacer bars approximately 3 ft (1 m) long were introduced and later tested successfully.

JPT

P. 1538＾
Error Characteristics of Extratropical-Storm Wind Fields Specified From Historical Data
Authors: Cardone V.J. , Broccoli A.J. , Greenwood C.V. , Greenwood J.A.
Published: December 2007

This study derives errors inherent in methods used to specify marine surface wind fields in hindcast studies of extreme environmental factors associated with extratropical storms. The northeastern Pacific Ocean is taken as the study basin, but results should apply to most Northern Hemisphere areas.

Introduction

As part of the selection process for environmental design data for offshore structures to be placed in regions exposed to severe storms, data on extreme waves, currents, and surge are generated, usually by the application of hydrodynamic models in historical hindcast studies. The need to describe accurately the temporal and spatial distribution of the surface over the sea arises both in calibrating the hydrodynamic models and in applying the models to long meteorological series to provide a data base of environmental extremes for statistical evaluation.

Specification of the most accurate wind field description possible is especially crucial in the calibration studies. There, it is important to isolate errors in predictions of environmental factors (waves, currents, and surge) that are related to model physics or numerics from those errors introduced by deficiencies in the wind field. Of course, accurate windfield specification is desired in long-term historical simulations, though the sparsity pf early history meteorological data places an upper bound on attainable accuracy. In lieu of high accuracy, it becomes important to determine the errors that characterize historical wind field descriptions and the impact of those errors on the accuracy and reliability of environmental series generated by hindcast models. While much work has been reported recently on development, calibration, and application of hindcast models, the specification and validation of wind fields has received little attention, at least for extratropical storms.

This study was designed specifically to determine the errors characteristic of alternative methods that have been used to specify marine surface wind fields in hindcast studies of extreme environmental factors associated with extratropical storms. The northeastern Pacific Ocean was taken as the test basin, but the results should apply to any extratropical region with a comparable meteorological data density (e.g., north Atlantic, North Sea, Bering Sea).
Modeling of a Deepwater Turbidite Reservoir Conditional to Seismic Data Using Principal Component Analysis and Multiple-Point Geostatistics
Authors: Strebelle Sebastien , Payrazyan Karen , Caers Jef
Published: December 2007

A new geostatistical approach, known as multiple-point statistics (MPS) simulation, recently has been proposed to generate 3D depositional facies models that integrate both large-scale information derived from seismic data and fine-scale information derived from well logs, cores, and analog studies. In this paper, the practicality, flexibility, and CPU advantage of this new approach are demonstrated through the modeling of an actual deepwater turbidite reservoir. First, based on well-log interpretation and a global geological understanding of the reservoir architecture, a training image depicting sinuous sand bodies is generated using a nonconditional object-based simulation algorithm. Then, disconnected sand bodies are interpreted from seismic amplitude data using a principal component cluster analysis technique, while a sand probability cube is generated using a principal component proximity transform of the same seismic. Multiple-point geostatistics allows simulating multiple realizations of channel bodies similar to the training image, constrained to the local sand probabilities, partially interpreted sand bodies, and well-log data. As illustrated in this paper, to account for uncertainty about the geometry of the sand bodies, different training images associated with alternative conceptual models proposed by the geologists can be considered.
Influence of Temperature and Clays/Emulsion Microstructure on Oil-Based Mud Low Shear Rate Rheology
Authors: Herzhaft Benjamin , Rousseau Lionel , Neau Laurent , Moan Michel , Bossard Frederic
Published: December 2007

Oil-based muds (OBMs) are complex fluids composed of water, oil, organophilic clays, and various additives. Their very good filtration and lubricating properties make their use beneficial in numerous drilling operations. Deep offshore operations may present phases using OBMs as drilling fluids. In these operations, the mud will experience extremely low temperature (down to 0°C) and low shear rate when flowing through the riser. It is therefore of primary importance to control mud rheological properties under such conditions.

This work presents a rigorous experimental study of OBM rheological properties using scientific rheometers. Temperature dependence and low shear rate behavior are specially studied. Because of their complex nature, OBM rheological properties will be extremely dependent on their microstructure. Characterization of this microstructure has therefore been sought during this study.

Several OBM compositions have been investigated. Flow curves have been established with a precise and reproducible procedure at temperatures varying from 0 to 80°C. For an offshore designed composition, a specific behavior at low shear rate has been detected. Two different regimes can be seen: a Newtonian behavior at low shear rate and a Herschel-Bulkley behavior at higher shear rate. The limiting shear rate value between the two regimes is dependent on temperature. Experiments on partial compositions (partial muds with/without solids, with/without clays) have shown that the specific clay used in this composition is responsible for this particular behavior at low shear rate. Oscillatory rheometry measurements have confirmed the existence of these two different regimes. CryoMeb and microscopic observations have allowed us to estimate the size of the emulsion droplets and of the clay particles. A simple energetic and structural model is proposed that fits the data well. Finally, a comparison is made between these experiments and those obtained using a Fann 35 (Fann Instrument Co., Houston) rheometer, concluding that classical Fann 35 measurements induce large error for low-shear-rate rheology.
Valuation of Technology and Information for Reservoir Risk Management
Authors: Raghuraman B. , Couët B. , Savundararaj P. , Bailey W. J. , Wilkinson D. J.
Published: December 2007

Reservoir risk management involves optimizing assets given inherent reservoir uncertainties and minimizing risk by reducing these accordingly. The decision to implement any reservoir management technology is usually based on some form of cost-benefit analysis. Consequently, the correct valuation of value-adding technology (often based on net present value, or NPV) becomes a significant part of a reservoir management process. This paper discusses techniques for the valuation of technology and information related to reservoir risk management. For demonstration purposes, these techniques are applied to valuation of real-time control and monitoring technologies in a reservoir with multiple uncertainties in its physical properties. Because of the presence of these uncertainties, value quantification requires a stochastic optimization of the reservoir production strategy, where the objective function includes a risk-aversion factor. By applying these techniques, one can generate a decision-making table that shows the benefit of implementing a technology at various confidence levels. One can then extend the analysis further to estimate the added value to the reservoir if the uncertainties were to be reduced (or even eliminated) by implementing appropriate monitoring technologies. This process enables quantification of the value of information and is useful in designing monitoring strategies.
Density Logging in the Gulf Coast Area
Authors: Campbell John L.P. , Wilson John C.
Published: December 2007

A radiation log, depending upon gamma rays scattered by and absorbed in the formation, gives a record from which the formation density can be derived. A comparison with laboratory measurements of cores sets the accuracy of the log at approximately 0.03 gm/cc.

In areas where lithological identification and correlation is difficult, the density log can give useful assistance.

The density log provides more representative and detailed density values for gravity meter interpretation than has been available from measurements made on either bit cuttings, well cores or outcrop samples.

Densities derived from the density log provide a means of calculating the formation porosity in limestone and sandstone reservoirs.

Introduction

Well logging equipment has been developed for measuring and recording many properties of the rocks through which the borehole passes, which are useful in the solution of exploration, well completion and petroleum production problems. Rock density or weight per unit volume of rock is a very important and basic rock property which has never been fully exploited. This has been due principally to the difficulty in making a suitable measurement of formation density from the borehole. However, within the past few years application of the strong effect of the density of materials on the absorption of gamma rays passing through them has provided a reliable means of making a continuous well log of formation density.

The density of materials can be measured in pounds per cubic foot but the metric unit, grams per cubic centimeter, is more commonly used because it is numerically equal to the specific gravity of the material, that is, the number of times the material is heavier than the same volume of water. The density of a rock is dependent upon the minerals of which it is composed. It varies from a low of 1.30 for lignites, through 2.05 for sulfur, 2.15 for salt, 2.31 for gypsum, 2.65 for clean non-porous sandstones, 2.71 for limestone, 2.85 for pure dolomites and 2.92 for anhydrite. These densities may be used for lithological identification of rocks which are known to be pure and non-porous. Fig. 1 illustrates the correlation of two logs showing density difference lithologically. However, many of the sediments are heterogeneous mixtures and cannot be identified on the basis of density measurement alone.
Nuclear Magnetic Resonance While Drilling in the Southern North Sea
Authors: Appel Matthias , Radcliffe Nigel J. , Aadireddy Prabhakar , Bonnie Ron J. M. , Akkurt Ridvan
Published: December 2007

Standard formation evaluation of an exploration well in the U.K. southern North Sea was supported by magnetic resonance while drilling (MRWD).

In this paper we show that even in tight gas sands, MRWD provides information about porosity and producible fluid fraction and allows estimation of formation permeability.

This successful introduction of MRWD technology in a known hard-rock environment illustrates a powerful addition to the logging-while-drilling (LWD) tool suite.
Bank Loans on Gasoline Plants
Authors: McGonagill Frank E.
Published: December 2007

This paper presents the various factors concern the economics of gasoline plant design, construction and operation from the viewpoint of a financial institution considering a loan. The gas reserves, plant design, processing equipment, marketing conditions, and estimated construction and operating expenses are reviewed and the information required for the proper evaluation of a loan discussed.

The information obtained from the study of the various factors affecting the economics of gasoline plant design, construction and operation are then considered together in predicting the economics of future operation. The effects of depreciation and income tax in the cash throw-off of a plant are also covered. This information is then used to Illustrate the type of loan, the amount that can be loaned, and the repayment ability of a proposed plant being considered.

In addition to the above, a discussion is presented of the legal information necessary for the proper processing of the loan and the various legal instruments which are prepared for the protection of the lender.

Introduction

During the past few years, the increased demand for natural gasoline, butane, and propane has made the operation of a natural gasoline plant profitable in small fields that were previously considered of no economic value. This has brought an increase in the number of small plants being constructed and has opened the door for small companies and individuals in a field that previously was dominated by major companies. It has been necessary for the small companies and individuals to turn to private lending institutions for financing these plant, since they have not been in a position to finance construction out of income or obtain funds from the sale of securities to the public as have the larger companies.

In order to properly make and service gasoline plant loans, it has been necessary for banks to set-up a yardstick which can be used as a basis for determining the value of a plant and the amount which can be safely loaned. It is desirable that such loans be arranged on a conventional basis; that is, for the amount loaned to be adequately secured by the value of the plant with a means of liquidation being provided by income generated by the plant. Such a loan is considered a secured loan and is the type which this paper will consider.
Integrated Interpretation of Wireline and 3D Seismic Data To Delineate Thin Oil-Producing Sands in San Jorge Basin, Argentina
Authors: Torres-Verdín Carlos , Chunduru Raghu K. , Mezzatesta Alberto G.
Published: December 2007

Hydrocarbon-bearing sand units in San Jorge basin, Argentina, exhibit a wide range of spatial variability and thickness. In view of this, a typical well is planned to vertically intersect as many sand units as possible. There are several problems faced by the petrophysicist in assessing whether a given sand unit should be perforated: (a) discrimination between oil- and water-bearing sands is not trivial because of very low-salinity water, (b) there exist substantial vertical variations of effective porosity within an individual sand because of shale laminations, and (c) it is often impossible to assess lateral extent away from the well. We have successfully addressed most of these difficulties with an interpretation procedure centered on the 2D inversion of wireline array-induction data. Two-dimensional inversion of array-induction data is necessary for the accurate estimation of shallow and deep resistivities, as well as the invasion length in light of significant shoulder-bed effects. This procedure has been complemented with the use of borehole nuclear magnetic resonance (NMR) data to provide estimates of effective porosity within individual sand units. Finally, we have made use of geostatistical inversion of 3D post-stack seismic data to estimate the lateral extent of hydrocarbon-bearing sands laterally away from wells. We present several application examples that yield results consistent with borehole testing and production data.
Development of the Alba Field—Evolution of Completion Practices, Part 2: Openhole Completions, Conventional Gravel Packing After Drilling With SOBM
Authors: Murray G. , Morton K. , Blattel S. , Davidson E. , McMillan N. , Roberts J.
Published: December 2007

Chevron has been successfully drilling and gravel packing openhole horizontal wells in the Alba field (central North Sea) since 1998, and 13 openhole gravel-packed (OHGP) wells drilled with water-based mud (WBM) are currently in production with no history of sand production. Although these wells have been hugely successful with significant net present value (NPV) returns, it was recognized that the future, mature redrill and infill targets cannot sustain the current costs associated with traditional OHGP completions. The challenge was to develop alternative techniques to maintain the benefits of OHGP wells but to achieve a low-cost well and completion concept to assist in realizing new drilling opportunities.

Drilling the shale above the top of the reservoir and the productive interval in a single hole section would require removing conventional requirements for setting an additional casing string and changing over to a water-based system before drilling into the reservoir. This would save costs but raises a question concerning the gravel-packing operation. Hitherto, attempts to gravel pack that involve alpha/beta placement techniques using an aqueous carrier fluid following drilling with oil-based systems have had only limited success.

The prospective problems were examined by extensive laboratory tests carried out cooperatively by Baroid and Chevron. A new, synthetic oil-based mud (SOBM) formulation was developed, and compatible displacement fluids and procedures were devised.

Based on this work, 1,500 ft of shale and reservoir were drilled, a liner that was predrilled over the reservoir section was installed, and screen was run inside the liner. Gravel was pumped using brine as the carrier fluid, and complete gravel placement was achieved. The well has achieved productivity levels at least as good as existing WBM wells. A second well completed in the same manner has given a similar performance.

This combination of a liner system and SOBM fluids offers several advantages. There is the prospect of considerable savings with respect to operating time, cementing, and drilling fluids. The liner also gives protection to the screen.

This new approach, which represents potential large savings in costs and excellent productivity, is considered applicable to other types of completions when it is desirable to drill with oil-based mud even though conventional thinking would have called for water-based drill-in fluid. This consideration applies to targets in the Alba field and worldwide.
Laboratory Evaluation of In-Situ Gelled Acids for Carbonate Reservoirs
Authors: Taylor K. C. , Nasr-El-Din H. A.
Published: December 2007

Three different commercial formulations (A, B, and C) of in-situ gelled acids are compared in detail at temperatures up to 150°F and acid concentrations from 5 to 20 wt% HCl. In-situ gelled acids are said to work by a gelation mechanism that occurs at the rock surface as the acid is spent. These acids contain a polymer, a crosslinker, and a breaker, in addition to other additives. Detailed viscosity measurements of each in-situ gelled acid were made with live, partially neutralized, and spent acid. A new experimental procedure was developed to partially neutralize the in-situ gelled acid with calcium carbonate, and then the apparent viscosity was measured as a function of shear rate in the range 1 to 3,000 s−1. The pH values of these samples varied from 0 to 6. Relative reaction rates with reservoir rock of the three in-situ gelled acids were compared at 100°F. Coreflood experiments were conducted with small acid volumes, so that permeability could be measured before acid breakthrough occurred.

In-situ gelled acids all retarded the reaction of acid with reservoir rock, primarily as a result of the polymer present in the acid formulae.

From viscosity measurements, live in-situ gelled acids A and B behaved more like gelled acids. Their viscosity in live acid was significantly higher than that of Acid C. In spent acid, the viscosity of Acid C was higher than that of Acids A or B. Acid C was most effective at initial HCl concentrations of 5 and 10 wt% at 100 and 150°F. Acids A and B were effective only at an initial HCl concentration of 10 wt% and 100°F.

Coreflood studies showed that the polymer and crosslinker component of in-situ gelled acids irreversibly reduced the permeability of carbonate reservoir rock.

As with any spent acids, mixing spent in-situ gelled acids with seawater resulted in calcium sulfate precipitation for all three of the acid systems.
Riser Slugging: A Mathematical Model and the Practical Consequences
Authors: Sagatun S. I.
Published: December 2007

This article presents a novel approach to estimating severe riser slug buildup time and, consequently, the slug period. The slug model is based on a simplified mechanical model. An explicit estimate of the slug buildup time is presented. The simplified slug model has subsequently been used to illustrate the effects of the traditional actions to prevent severe riser slugging. The slug model is subsequently tested against field data from an offshore floating production platform and large-scale experimental data, as well as data from the literature. The experimental setup is described in detail. The estimate on the slug buildup time provided by the simplified model matches well the experimental data, the field data, and data from relevant references.
Unsteady-State Water Influx in Elliptic and Anisotropic Reservoir/Aquifer Systems
Authors: Kucûk Fikri , Brigham William E.
Published: December 2007

This work investigates the behavior of elliptical and anisotropic aquifers. Solutions for the dimensionless cumulative water influx and rate of water influx are presented for a range of ae/be ratios (ae/be = ratio of the half-length of major to minor axes of the internal boundary ellipse). Tabular and graphical forms of the dimensionless cumulative water influx and influx rate are presented as a function of the dimensionless time for various internal boundary geometries ranging from ae/be = 1, which corresponds to a circle, to a ae/be = ∞, which corresponds to a line (linear system). It is shown also that, for long times, an elliptical aquifer/reservoir system can be treated as a radial system by using the effective radius presented here as a function of the ae/be ratio.
Integration of Multiphase Flowmetering, Neural Networks, and Fuzzy Logic in Field Performance Monitoring
Authors: Alimonti C. , Falcone G.
Published: December 2007

The usual approach to the interpretation of producing wells is based on mechanistic models for the simulation of steady-state and transient flow regimes. However, there are significant reservations about convergence problems, computational limits, the need for extensive tuning on field data, the instability of boundary conditions, the limited applicability of existing multiphase flow models, and the uncertainties associated with choke-valve models. The current industry standards are critically reviewed within this framework.

The real-time monitoring of producing wells is recognized as the best way of optimizing field performance. Monitoring a producing well implies the ability to track any changes in fluid composition, flow rates, or pressure and temperature profiles in real time. Multiphase flowmetering (MFM) plays a key role in this scenario. Such information, combined with the critical analysis of historical data from the well itself or from analog wells, allows diagnosis of the system and prediction of future trends. However, field data per se do not necessarily generate knowledge. This is particularly true for large databases, which are difficult to manipulate to provide suitable inputs for wellbore simulators.

This paper suggests how MFM, knowledge discovery in databases (KDD), and fuzzy logic (FL) can offer an alternative approach to analyzing producing wells. KDD is the automated extraction of patterns representing knowledge implicitly stored in large information repositories. Distributed, ad hoc field measurements (including MFM and downhole measurements) can be processed by means of data cleaning, data integration, data mining, artificial intelligence (AI), and pattern evaluation. FL can then manage the resulting information in terms of flow assurance and production optimization.

The same techniques can also be extended to the reservoir and production network for an integrated approach to production-system analysis.
Optimized Design of Pipe-in-Pipe Systems
Authors: Hausner M. , Dixon M.
Published: December 2007

Deepwater subsea developments must address flow-assurance issues, and these increasingly form a more critical part of the design. Pipe-in-pipe (PIP) systems, one of the options available in the designers’ toolbox for overcoming these problems, are recognized as thermally efficient, reliable, and proven technology for insulated, subsea transportation of wellbore fluids. Although extremely low U values are achievable, PIP systems come at a cost, with increased weight as a penalty for use in deepwater developments.

By applying an "inside-out" optimization process for the design of PIP systems, the top-tension loading on the surface vessel (installation or production) can be reduced significantly while minimizing procurement expenditure on raw materials. Specifically, the design optimization of each component reduces steel volumes as well as the overall outer diameter (OD) of the system.

This paper presents the methodology for optimized design of PIP systems and illustrates the potential cost savings in terms of raw materials and installation through a case study for a typical large west African field. Commercial savings related to surface platform hull costs also are presented for a case in which the development employs PIP in catenary risers.
Developing New Fields Using Probabilistic Reservoir Forecasting
Authors: Kabir C. S. , Chawathé A. , Jenkins S. D. , Olayomi A. J. , Aigbe C. , Faparusi D. B.
Published: December 2007

Limited and uncertain geologic and engineering data at the onset of any new field development are the bane of reservoir characterization and simulation. The problem stems from the uncertainty in various model-input variables, such as reservoir connectivity, fluid viscosity, and endpoint saturations, to name a few. Given this scenario, an ad hoc, one-factor-at-a-time approach to earth and flow-simulation modeling cannot possibly yield unbiased information for making objective business decisions.

This study presents three field cases in which both engineering and earth-model variables were varied in a systematic way to assess reservoir performance by use of the experimental design (ED) approach.

Results of the field cases show that well requirements (both producers and injectors) turned out to be fewer than anticipated. Equally important, one case study showed that laboratory measurements could minimize uncertainty surrounding oil viscosity and endpoint saturations. At the same time, we learned that the preferred horizontal-well orientation was marginally superior to vertical wells in light of high reservoir anisotropy. In another case, stratigraphy, gas/oil contact (GOC), and aquifer strength became the primary variables for the full-factorial design after the initial screening. Here, we proved that the project could proceed because it met the minimum reserves criterion. Perhaps most importantly, all studies showed how to obtain unbiased information in far fewer flow-simulation runs than one would do using an ad hoc approach.
PDC Bit Classification According to Steerability
Authors: Menand S. , Sellami H. , Simon C.
Published: December 2007

With the emergence of rotary steerable systems (RSSs), the technical issue concerning bit design for a specific directional application has reappeared. Today, a bit must be specifically designed for use with a particular directional system: rotary bottomhole assembly (BHA), steerable mud motor, or RSS. The reason is that the bit must have the ability to respond properly and rapidly to a side force applied by the steering system to initiate a deviation. To do so, the bit must have a predetermined steerability compatible with the directional system to provide the optimum dogleg potential.

The new generation of directional-drilling systems differentiates "pointing the bit" from "pushing the bit." As a consequence, the bit's directional response is a key factor that operators and directional drillers need to know to make a good adaptation between the bit and the BHA. However, at the moment there is no standard method for classifying bits by steerability and walking tendency.

On the basis of a comprehensive analysis of the directional behavior of polycrystalline diamond compact (PDC) bits (numerical simulation and pilot and field tests), a simple methodology has been developed that defines and evaluates their steerability and walking tendency. This methodology is used to classify the PDC bits defined with their IADC bit profile codes.

Because PDC bit steerability is mainly a function of the bit profile, the gauge cutters, and the gauge pad, some design recommendations are given concerning these three parts. For each IADC bit profile code, the bit steerability and walking tendency are estimated through some formulas linking only the heights and lengths of the cutting profile. Some guidelines are also given about the gauge-pad length and gauge-cutter characteristics to achieve improved steerability.

This simple method based on geometrical criteria allows quick estimation of not only the PDC bit steerability but also the maximum dogleg potential achievable by the bit when it is coupled with the steering system.
A Generalized Wellbore and Surface Facility Model, Fully Coupled to a Reservoir Simulator
Authors: Coats B. K. , Fleming G. C. , Watts J. W. , Ramé M. , Shiralkar G. S.
Published: December 2007

The formulation of a black-oil or compositional fully coupled surface and subsurface simulator is described. It is based on replacing the well model in a conventional reservoir simulator with a generalized network model of the wells and facilities. This allows for representation of complex wellbore geometry and downhole equipment. The method avoids the inefficiencies and/or inaccuracies of other coupled models, in which wells and facilities are treated as separate domains or in which the global system is not solved simultaneously. Example cases demonstrate the performance of the model for cases with simple and segmented wellbores (with and without facilities).
Productivity Preservation Through Hydraulic Propped Fractures in the Eldfisk North Sea Chalk Field
Authors: Cook C. C. , Brekke K.
Published: December 2007

The Eldfisk oil field is a high-porosity, low-permeability reservoir of soft chalk in the Norwegian North Sea. Commercial oil production from the Eldfisk field is dependent on well stimulations. To date, pseudolimited-entry acid stimulation (PLEAS) has been the standard completion technique. This technique initiates relatively high (5,000 BOPD) individual-well oil-production rates. Over time, however, many of the Eldfisk wells have experienced rapidly declining oil production characterized by wellbore skin increase and fracture closure. Solids production and casing collapse have also been problematic. In late 1997, an alternative completion technique involving four hydraulic propped-fracture stages was successfully executed in an Eldfisk horizontal well. This paper presents a simple methodology to evaluate sustained productivity enhancement of propped fractures vs. acid stimulations in soft chalk formations based on the use of analytical modeling in combination with empirical production-data analysis.
Effect of Oil Composition on Miscible-Type Displacement by Carbon Dioxide
Authors: Holm LeRoy W. , Josendal Virgil A.
Published: December 2007

This paper presents additional data related to the correlation between minimum miscibility pressure (MMP) for CO2 flooding and to the composition of the crude oil to be displaced. Yellig and Metcalfe have stated that there is little or no effect of oil composition on the MMP. However, their conclusion was based on experiments with one type of reservoir oil that was varied in C1 through C6 content and in the amount of C7+ present but not varied in composition of the C7+ fraction. We have found that the Holm-Josendal correlation, which is based on temperature and C5+ molecular weight, predicts the general trend of the MMP's required for CO2 flooding of various crude oils. MMP's were predicted with this correlation and then tested for several crude oils using oil recovery of 80% at CO2 breakthrough and 94% ultimate recovery as the criteria. We now have data showing that miscible-type displacement is also correlatable with the amount of C5 through C30 hydrocarbons present in the crude oil and with the solvency of the CO2 as indicated by its density. Variations from such a correlation are shown to be related to the C5 through C12 content and to the type of these hydrocarbons.

The MMP data were obtained from slim-tube floods with crude oils having gravities between 28 and 44°API (0.88 and 0.80 g/cm3) and C5 + molecular weights between 171 and 267. The crude oils used varied in carbon residue between 1 and 4 wt% and in waxy hydrocarbon content between 1 and 17%. The required MMP for these crude oils at 165°F (74°C) varied between 2,450 and 4,400 psi (16.9 and 30.3 MPa) for an oil recovery of 94% OIP. The MMP was found to be a linear function of the amount of C5 through C30 hydrocarbons present and of the density of the CO2.
Compositional Effects on Displacement Mechanisms of the Micellar Fluid Injected in the Sloss Field Test
Authors: Gupta Surendra P.
Published: December 2007

The performance of the micellar/polymer flood conducted in the Sloss reservoir did not follow predictions by a streamtube model. The model assumed that micellar flood displaces oil and water in a piston-type miscible manner with a final oil saturation of 5% PV, and sulfonate retention based on short-term laboratory adsorption tests. This paper, in conjunction with a complementary paper,1 describes process mechanisms needed to model the flood performance.

The results of laboratory studies show higher sulfonate retention caused by ion-exchange effects, which result in partitioning of sulfonate into the oil phase and higher adsorption caused by long contact times. Long-term aging of the Sloss micellar fluid at the high reservoir temperature (93.3°C [200°F]) does not reduce oil recovery. The results of laboratory studies also show that the final oil saturation after micellar flooding is capillary-number dependent. A higher final oil saturation can be the result of reduced injectivity/productivity, increased interfacial tension (IFT), and/or decreased viscosity.

This paper demonstrates that ion exchange, hardness, and sulfonate partitioning can significantly affect micellar-flood performance. The paper presents an experimental plan that provides information for optimizing the design of micellar/polymer floods. This plan, when applied to a specific flood, allows an investigator to examine effects of adsorption, ion exchange, hardness, and partitioning on flood performance. Specifically, phase studies and sulfonate requirements must encompass effects of in-situ-generated calcium ions as a result of sodium/calcium ion exchange. Sulfonate itself can increase the calcium content of the fluids because of a calcium/micelle association. High calcium concentrations can increase sulfonate requirements. Sulfonate adsorption requirements for micellar flood design are sensitive to the experimental procedures employed. The paper outlines improved procedures encompassing ion exchange and time effects and demonstrates that a favorable ion-exchange process can be used to reduce adsorption requirements.
A Comparison of Two-Phase Inflow Performance Relationships
Authors: Gallice Frederic , L. Wiggins Michael
Published: December 2007

Petroleum engineers are routinely required to predict the pressure/ production behavior of individual oil wells. These well-performance estimates assist the engineer in evaluating various operating conditions, determining the optimum production scheme, and designing production equipment and artificial-lift systems.

In this paper, commonly used empirical, inflow performance relationships for estimating the pressure/production behavior during two-phase flow are investigated. Relationships studied include those proposed by Vogel; Fetkovich; Jones, Blount, and Glaze; Klins and Majcher; and Sukarno and Wisnogroho. Each method is described briefly, and the methods used to develop the relationship are discussed.

On the basis of actual vertical-well data, the relationships are used to predict performance for 26 cases. The predicted performance is then compared to the actual measured rate and pressure data. The variation between the predicted and measured data is analyzed, and from this analysis, an assessment is made on the use of inflow performance relationships and of the quality of the performance estimates.
A Closed-Form Hydraulics Equation for Aerated-Mud Drilling in Inclined Wells
Authors: Guo Boyun , Sun Kai , Ghalambor Ali , Xu Chengcai
Published: December 2007

Accurate prediction of shut-in and flowing bottomhole pressures (BHPs) in inclined holes presents a challenge in aerated-mud drilling. It is highly desirable to develop a simple and accurate hydraulics equation for this purpose. This paper fills the gap.

A closed-form hydraulics equation was developed in this study on the basis of recent experiments on multiphase flow in an inclined-well model. The newly developed hydraulics equation is a four-phase model that considers injected liquid, injected gas, formation-fluid influx, and cuttings entrained at the bottom of the hole during drilling. It degenerates to the Poettman and Bergman equation when terms for friction loss, cuttings weight, gas weight, and temperature variation are neglected.

The equation was first calibrated with the data measured from a full-scale research borehole. It was then tested with two field cases covering a deep (7,403 ft vertical depth) and a shallow (697 ft vertical depth) horizontal well drilled with aerated muds. The results show 3.42 and 0.8% error of the equation in BHP prediction for the deep and shallow wells, respectively. The equation was also compared with two commercial software packages (S1 and S2) using the measured BHP from another well. It indicates that the flowing BHP calculated by the equation is comparable to that from S1 and much more accurate than S2. Sensitivity analyses with Eq. 7 show that the gas-injection rate affects "static" pressure more than flowing pressure in the annular space for the tested data range. The sensitivity analyses also indicate very high equivalent circulating density (ECD) and low equivalent mud weight (EMW) in shallow depths near the surface.
Inflow Performance Relationship for Perforated Horizontal Wells
Authors: Yildiz Turhan
Published: December 2007

This paper presents an investigation of perforated horizontal-well performance in areally anisotropic reservoirs. Theoretical investigation is based on a 3D analytical IPR model. The analytical IPR model considers an arbitrary distribution of perforations along the completed segments. Changes in flow rate, pseudosteady-state productivity, and cumulative production can be computed using the solution.

The analytical IPR model was compared with the models available in the literature and verified. It was then used to investigate the effects of well and reservoir parameters on the inflow performance of perforated horizontal wells.
Productivity of Horizontal Wells Completed With Screens
Authors: Yildiz Turhan
Published: December 2007

An integrated flow model is developed to simulate the flow into horizontal wells with screens. The model is composed of a multisegment horizontal-well model and a near-wellbore model. The multisegment horizontal-well model predicts the pressure losses in a bounded reservoir. The near-wellbore model simulates the fluid flow through the damaged/collapsed zone around the wellbore, the mudcake, the wellbore/screen interface, the gravel-packed annulus, and the screen itself.

Using the model, we investigated the effects of degree of screen damage, nonuniform damage removal, mudcake properties, and blank-pipe insertion on horizontal-well productivity. We examined and compared the long-term horizontal-well performance in terms of rate decline and cumulative production as a function of time.
The Effective Compressibility of Reservoir Rock and Its Effects on Permeability
Authors: McLatchie A.S. , Hemstock R.A. , Young J.W.
Published: December 2007

Results and experimental procedures are presented covering a preliminary laboratory investigation of the compaction of reservoir rocks and its effect on porosity and permeability.

"Effective" compressibility was measured by subjecting core material to an overburden load and reducing pore pressure. Preliminary results showed relatively high effective compressibilities which varied from 1.8 × 10(–6) pore volume/pore volume/lb/in. for limestones to 7.7 × 10(–6) pore volume/pore volume/lb/in. and even higher for sandstone reservoirs containing large amounts of fine clay material. It appeared from the initial results that the effective compressibility of the material could not be correlated directly with porosity and that other factors, such as the amount of clay material present might have to be taken into account. The work to date has indicated that effective compressibility factors will have to be measured for the particular reservoirs being studied.

Oil permeability of core material was measured under various effective overburden loads from 0 to 8,000 psi. It has been found that reduction of permeability in clean sands was relatively small and the results agreed with published data. For sandstones containing large amounts of clay, preliminary tests indicated very large reductions in permeability with increasing effective overburden pressures. It is planned to continue laboratory work on this phase because of its importance in low-permeability reservoirs.

Introduction

During the past few years increasing interest has been shown in the differences obtained between conventional laboratory measurements on cores at atmospheric pressure and those when reservoir conditions are simulated. Since these data are used as the basis for calculations and the prediction of reservoir behavior, their evaluation under reservoir conditions is most important.

The effect of the compressibility of the rock upon the reservoir behavior, as fluid pressure declines, is an important subject which has been insufficiently studied. The total pressure on any plane through a reservoir is the result of the grain-to-grain rock pressure due to the overburden and the pressure of the interstitial fluid on the plane.
Finite Element Model Simulations Associated With Hydraulic Fracturing
Authors: Advani Sunder H. , Lee J. K.
Published: December 2007

Recently emphasis has been placed on the development and testing of innovative well stimulation techniques for the recovery of unconventional gas resources. The design of optimal hydraulic fracturing treatments for specified reservoir conditions requires sophisticated models for predicting the induced fracture geometry and interpreting governing mechanisms.

This paper presents methodology and results pertinent to hydraulic fracture modeling for the U.S. DOE's Eastern Gas Shales Program (EGSP). The presented finite-element model simulations extend available modeling efforts and provide a unified framework for evaluation of fracture dimensions and associated responses. Examples illustrating the role of multilayering, in-situ stress, joint interaction, and branched cracks are given. Selected comparisons and applications also are discussed.