bluuebunny/crossref_metadata_2025 huggingface dataset:
Kuparuk Large-Scale Enhanced Oil Recovery Project
Authors: Hoolahan S. P. , McDuffie G. S. , Peck D. G. , Hallam R. J.
Published: December 2007

The Kuparuk River oil field has had a "miscible" water-alternating-gas (MWAG) enhanced-oil-recovery (EOR) pilot in place since 1988. This original pilot was implemented on two drillsites previously on waterflood. The pilot was expanded to a third drillsite in 1993 to test the MWAG process in an area previously flooded by an "immiscible" water-alternating-gas (IWAG) recovery technique. Large-scale application of MWAG at Kuparuk is in progress, with a project that will more than triple current MWAG injection. Full implementation is slated for mid-1996. When completed, the Kuparuk large-scale EOR (LSEOR) project will be among the largest of its kind in the world. This paper covers the basic aspects of moving the EOR process at Kuparuk from pilot to large-scale application. A number of hurdles had to be overcome, including scaleup of field and simulation results in a consistent manner and the need to use existing infrastructure to ensure economic viability
Prudhoe Bay Gas/Oil Relative Permeability
Authors: Jerauld G. R.
Published: December 2007

Prudhoe Bay is a mixed-wet reservoir where about half the oil recovery is attributable to gravity drainage. Gas/oil relative permeability data show that gravity-drainage recovery efficiency is poorer for more fine-grained sandstone and increases as the grain size increases. Gravity-drainage efficiency also increases with connate-water saturation. Dependence of recovery efficiency on grain size is related to changes in sorting. An effective grain size, defined by inverting the Carman-Kozeny relation, provides a useful parameter for correlating recovery efficiency. This estimate correlates well with visual estimates and direct measurements on disaggregated core. Grain size is also found to be a more effective parameter for correlating trapped gas than porosity, a common alternative. Lithology impacts trapped-gas level with finer-grained, more poorly sorted rock having higher trapped gas. Trapped gas decreases with increasing microporosity. Because little gas is trapped in microporosity, a zero-slope generalization of the Land curve better represents trapped-gas data.
Integrating Multiphase Production History in Stochastic Reservoir Characterization
Authors: Vasco D. W. , Datta-Gupta Akhil
Published: December 2007

This paper focuses on integrating field-production history into reservoir characterization through stochastic inverse modeling. A key element of our approach is a three-dimensional (3D) streamline simulator that is orders of magnitude faster than traditional numerical simulators and thus allows for rapid inversion of multiphase production data. Stochastic permeability fields, conditioned to field-production history, are then generated with simulated annealing. We also explore the spatial resolution associated with estimates of reservoir permeability variations derived by use of field-production history. On the basis of techniques from geophysical inverse theory, we address such issues as data sensitivity, spatial resolution, averaging kernels, and uncertainties associated with our estimates of reservoir permeability. The proposed inversion technique has been applied to synthetic as well as field cases. The synthetic example involves a sensitivity analysis of multiphase production history in heterogeneous five-spot and nine-spot patterns. The field example consists of production history from a five-spot pattern in the north Robertson unit, a low-permeability carbonate reservoir in West Texas. Watercut history at the producers are used to estimate permeability variations in a two-layer (matrix-fracture) model of the reservoir. All computations were performed on a 125 MHz Pentium with an average run time of about 4 wall-clock hours, indicating the feasibility of our approach.
Influence of Water on Estimation of Gas in Place
Authors: de Hemptinne J-C. , Zhou Honggang , Moracchini Gérard , Brunella Isabelle
Published: December 2007

The usual method for determining the gas in place (GIP) in a reservoir uses a balance equation based on laboratory measurements of the raw gas volumetric factor as a function of pressure on a water-free basis. In the reservoir, however, the gas is saturated with water. Volumetric measurements at high temperatures and pressures have been performed on a North Sea fluid at 374°F, both in water-free conditions and in the presence of an excess water. The water content of the gas at 650 bar has been determined to be 3.5 mol% (3.6 mole of water/100 mole of reservoir fluid) water-saturated reservoir fluid. A corresponding volume increase of 3.2 % has been detected. These experimental measurements have been correlated with a Tait-type equation. The S0reide and Whitson1 model has been used to calculate the water content of the gas. A modified balance equation is proposed for prediction of the GIP.
Determination of Three-Phase Relative Permeabilities From Displacement Experiments
Authors: Nordtvedt J. E. , Ebeltoft Einar , Iversen J. E. , Sylte André , Urkedal Hege , Vatne K. O. , Watson A. T.
Published: December 2007

We describe and demonstrate a method for the determination of three-phase relative permeability functions at reservoir conditions. Two- and three-phase displacement experiments are conducted on a low-permeability chalk sample, and estimates of the three-phase relative permeability and capillary pressure functions are obtained. We also calculate three-phase relative permeabilities with the Stone predictive model, and we evaluate them by simulating the experimental data.
A New Method To Calculate Effective Permeability of Gridblocks Used in the Simulation of Naturally Fractured Reservoirs
Authors: Lough Michael F. , Lee Seong H. , Kamath Jairam
Published: December 2007

Current simulation technology for naturally fractured reservoirs is based on either the continuum or the discrete-fracture approach. The more commonly used continuum model can simulate complex recovery mechanisms. However, it uses a very simplified representation of the fracture system for calculating effective fracture permeability. The discrete-fracture flow method can handle complex fracture geometry. However, its use has been typically limited to basic flow calculations through a connected fracture system embedded in zero-matrix-permeability rock.

We have developed a new technique for estimating the effective permeability of gridblocks used in conventional simulators. The idea behind this technique is to integrate the realism of fracture systems, as captured by discrete-fracture models, with the complexity of the flow calculations offered by continuum models. The end product of developing this technique is an efficient numerical code based on the boundary-element method. This code permits the fracture system to be complex and poorly connected, and it also includes the contribution from flow through the matrix rock. For fluid flow in the matrix rock, the fractures are treated as planar-source distributions. Periodic boundary conditions, for the flow properties, are used for the calculation of the effective permeability of individual gridblocks.

We first use a simple fracture system to demonstrate the validity of our method and to evaluate the sensitivity of the results to matrix and fracture properties. We then use fracture statistics data from the Mesaverde sandstone, effective permeability values from our code, and a continuum simulator to calculate tracer-flow patterns for a more realistic system.
Models for Heat Transfer from a Buried Pipe
Authors: Archer Rosalind A. , O'Sullivan Michael J.
Published: December 2007

Analytical solutions are presented for the temperature distribution along a buried pipe. Two different geometries are used to model the surrounding material, and isothermal and convective boundary conditions at the pipe wall are considered. Firstly an ‘effective cylinder’ model in which the burial medium is modelled as a homogeneous annular layer around the pipe is considered and secondly a ‘half-space’ model in which the pipe is modelled as a cylinder in an infinite half-space is used. The effective cylinder configuration is of importance because it is often used in more complex computational heat transfer models. In both models coupled differential equations representing conservation of energy in the pipe and its surroundings are solved. By comparing the solution for the effective cylinder model to that for the physically more realistic half-space model, the most suitable radius of the annular layer of material in the effective cylinder model can be calculated. For a deeply buried pipe the effective cylinder radius tends to twice the burial depth of the pipe. This work also gives a calculation of the effective conductivity of the burial medium when two different materials are used, such as is the case when a pipe is placed in a trench and covered in backfill material.
Field Evaluation of a Multiphase Meter in Well-Testing Operation
Authors: Shen J. J. S. , Riley R. C.
Published: December 2007

This paper describes the evaluation results on the measurement accuracy and long-term operation of a multiphase meter used for well testing. The test was conducted by Chevron at its Lost Hills field in California. After many years of development work, several multiphase meter manufacturers have begun to offer their meters commercially for production operation. In this paper, commercial multiphase meters are first briefly reviewed based on the methods that those meters use to handle the fluid flow. The multiphase meter selected for this application was manufactured by Accuflow Inc. It uses the compact separation approach in handling the oil/gas/water flowstream by first separating the gas from the liquid stream and then measuring the gas and oil/water separately. The Accuflow system was installed at a gauge station in January 1996. It was designed to test wells that have productions ranging approximately from 100 to 400 bbl of fluid per day, with a high water cut (40 to 90%), and up to 200 Mcf/D of gas. For accuracy testing, the multiphase meter was piped in series with a test separator at the gauge station. Production from selected wells, covering a wide range of flow rates, water cuts, and gas volume fractions, flowed through the multiphase meter first and then through the test separator, which enabled comparison of the new meter's performance and accuracy with an existing reference. Additional tests also were conducted to compare results with a test tank at the site. The paper also discusses other operational aspects of the multiphase meter such as equipment maintenance and sand accumulation. Overall, satisfactory performance of this multiphase meter was observed, and additional units have been installed at the Lost Hills field.
Mapping Steam and Water Flow in Petroleum Reservoirs
Authors: Wilt Michael , Schenkel Clifford , Daley Tom , Peterson John , Majer Ernest , Murer A. S. , Johnston R. M. , Klonsky Louis
Published: December 2007

During the past 5 years, we have applied high-resolution geophysical methods [crosswell seismic and electromagnetics (EM) and passive seismic] to map and characterize petroleum reservoirs in the San Joaquin Valley and to monitor changes during secondary-recovery operations. The two techniques provide complementary information. Seismic data reveal the reservoir structure, whereas EM measurements are more sensitive to the pore-fluid distribution. Seismic surveys at the South Belridge field were used to map fracture generation and monitor formation changes caused by the onset of steamflooding. Early results show possible sensitivity to changes in gas saturation caused by the steamflooding. Crosswell EM surveys were applied at a shallow pilot at Lost Hills for reservoir characterization and steamflood monitoring. Images made from baseline data clearly show the distribution of the target oil sands; repeated surveys during the steamflood allowed us to identify the boundaries of the steam chest and to predict breakthrough accurately. Applications of the EM techniques in steel-cased wells are at an early stage, but preliminary results at Lost Hills show sensitivity to formation resistivity in a waterflood pilot.
The Stratigraphie Method: A Structured Approach to History-Matching Complex Simulation Models
Authors: Williams M. A. , Keating J. F. , Barghouty M. F.
Published: December 2007

This paper offers a structured approach to performing a history match on a complex, multilayered reservoir model. We recommend tools for interpreting the data and simulation results, and discuss procedures for improving the quality and efficiency of the history-matching process. This approach, the stratigraphic method (SM), was developed over 10 years on various reservoir studies. It has been used successfully on highly complex reservoirs, some containing more than 1,700 wells and over 50 years of production history. We also report on which reservoir parameters most affect matching observed-reservoir performance. This may be helpful to those with less experience working on a history-match project.
Permeability Determination Using Neural Networks in the Ravva Field, Offshore India
Authors: Wong P. M. , Henderson D. J. , Brooks L. J.
Published: December 2007

This paper describes the use of the backpropagation neural network (BPNN) technique to predict reservoir permeability using conventional well log data. The technique is demonstrated with an application to the Ravva oil and gas field, offshore India. The Ravva field reservoirs are middle Miocene age nearshore marine sandstones that are often laminated to thinly interbedded shale. The use of conventional permeability-porosity crossplots to predict permeability in this field was not successful. The BPNN permeability prediction model ("RAVVANET") was developed from a data set consisting of core permeability and well log data from two early development wells. The model was blind tested with data from a third well, which was withheld from the modeling process. The results of this study show that BPNN model permeability predictions are consistent with core analysis results.
Acid-Fracturing Treatment: A Surface-Topography Analysis of Acid-Etched Fractures To Determine Residual Conductivity
Authors: Ruffet C. S. , Féry J-J. , Onaisi Atef
Published: December 2007

A fracture-acidizing treatment of carbonate formations can be considered successful when a relatively good fracture conductivity remains after treatment. To reach such a goal, an uneven etching of the fracture by acid is expected, so that channels are created that hydraulically maintain the fracture open, once the pressure is released after the job, and thus enhance productivity.

Residual conductivity is the consequence of uneven etching of the surface, but the way this etching occurs in the field is not well understood and, therefore, poorly described. We, thus, propose, in this paper, an experimental methodology to investigate and characterize quantitatively how acid injection conditions affect the fracture surfaces, how the created rough surface is able to support the stress, and, finally, how fracture conductivity can be estimated from the surface topography.

The statistical investigation of surface topography associated with acidizing experiments proposed in this paper, provides a new and interesting method for designing an acid fracturing job. It can be used as an aid to select the best fluid formulation and flow rate for a given formation type and well conditions and to forecast the behavior of the fracture after the treatment.
Prediction of Interfacial Tensions of Reservoir Crude Oil and Gas Condensate Systems
Authors: Zuo You-Xiang , Stenby E. H.
Published: December 2007

In this work, the linear gradient theory (LGT) model, the simplified linear gradient theory (SLGT) model, the corresponding-states (CS) correlation, and the parachor method developed by the authors1–4 were extended to calculate interfacial tensions (IFT's) of crude oil and gas condensate systems. Correlations of the model parameters were presented for pseudocomponents. The characterization procedures of Pedersen et al.5 and the SRK equation of state (EOS)6 were used to calculate vapor-liquid equilibria (VLE). To the exclusion of the near-critical region, the IFT's calculated by all the models except the CS correlation were in good agreement with the measured IFT data for several crude oil and CO2/oil systems. The SLGT model and the parachor model perform better than the LGT model and the CS correlation. For N2 volatile oil systems, the performance of the LGT model is better than that of the SLGT model and the parachor model. For gas condensate systems, the predictions by use of the SLGT model are in good agreement with the measured IFT data. In the near-critical region, a correlation was proposed for estimations of IFT's for CO2/oil systems, and satisfactory correlated results were obtained.
Permanent Gauge Pressure and Rate Measurements for Reservoir Description and Well Monitoring: Field Cases
Authors: Unneland Trond , Manin Yves , Kuchuk Fikri
Published: December 2007

This paper presents a procedure for interpreting data acquired with permanent downhole pressure sensors in association with surface or downhole rate measurements. The usefulness of this data source in reservoir description and well performance monitoring is illustrated.

Unlike previously published examples, this interpretation is based on the analysis of a stream of data acquired over a long period of time, thus taking advantage of the continuous nature of the measurements. Three field cases are presented using the pressure and rate data in decline-curve analysis for wells with a variable downhole flowing pressure.

Because such an interpretation is conducted while production continues, the interpretation is particularly well suited for a well or group of wells under extended testing that are equipped with downhole gauges and are flowing through surface separation and metering systems. Wells completed with both permanent downhole rate and pressure measurements are also ideal candidates for this analysis.

Finally, the influence of the pressure sensor long-term drift and the rate measurement error on the interpretation results and future forecasts are investigated.
Productivities of Fractured and Nonfractured Deviated Wells in Commingled Layered Reservoirs
Authors: Larsen Leif
Published: December 2007

Direct analytical methods are introduced to determine productivity indices of fractured and nonfractured deviated wells in commingled layered reservoirs, including cases with horizontal wells. For non-fractured wells, the total productivity index (PI) can be obtained by adding the individual layer PI's. A similar straightforward addition scheme can also be used for many fractured wells, but a more direct approach covering all well and fracture elements might be needed if at least one of the fractures penetrates more than one additional layer above or below the wellbore layer.
Steady-State and Transient Thermal Performance of Subsea Hardware
Authors: Zabaras G. J. , Zhang Jianfeng
Published: December 2007

The thermal performance of subsea hardware is of ultimate importance to the economic development and reliable operation of deepwater subsea oil and gas systems because of the potential for hydrate formation. Results of numerical calculations are presented on the thermal performance of subsea equipment such as wellheads, tubing and flowline jumpers, and flowline field joints. In contrast to previous published studies on the thermal performance of insulated subsea wellbores and flowlines, this paper addresses the thermal performance of the subsea equipment that can provide weak thermal links for the subsea system.

Although subsea insulated flowlines can eliminate or reduce the risk of hydrate formation during steady-state production, they may not provide sufficient cooldown time before hydrates are formed during an emergency shutdown. Subsea wellheads, pipe field joints, manifold jumpers, and flowline and tubing jumpers are very difficult to insulate effectively. As a result, these pieces of equipment exhibit faster cooldown to hydrate-formation temperature than does either the wellbore or the flowline.

A two-dimensional (2D), general-purpose, finite-element, partial-differential equation solver was used to analyze the steady-state and transient thermal behavior at different cross sections of the subsea tree. In contrast to the intuitive common belief that a subsea-tree cooldown time to hydrate-formation temperature is on the order of several hours, a cooldown time less than 2 hours was determined after a system shutdown. Steady-state analysis of a flowline field joint indicates that the joint degrades the flowline thermal performance, causing up to a 20% increase in the flowline overall heat-transfer coefficient. To our knowledge, such results have not yet been presented in the literature.

This paper presents a new method for predicting pressure profiles in oil and gas wells. The method combines mechanistic flow-pattern transition criteria with physical models for pressure-loss and liquid-holdup calculations for each of the flow patterns considered. Past published methods relied heavily on empirical fit of limited field data. As a result, they are inaccurate when used outside the range of data upon which they are based. In contrast, the new method is universally applicable to all types of wells under all operating scenarios because it is based on fundamental physics rather than the curve-fit of field data. Its prediction performance has been demonstrated by extensive comparison to field data from a variety of wells.
EOR Screening Criteria Revisited—Part 2: Applications and Impact of Oil Prices
Authors: Taber J. J. , Martin F. D. , Seright R. S.
Published: December 2007

Screening criteria are useful for cursory examination of many candidate reservoirs before expensive reservoir descriptions and economic evaluations are done. We have used our CO2 screening criteria to estimate the total quantity of CO2 that might be needed for the oil reservoirs of the world. If only depth and oil gravity are considered, it appears that about 80% of the world's reservoirs could qualify for some type of CO2 injection.

Because the decisions on future EOR projects are based more on economics than on screening criteria, future oil prices are important. Therefore, we examined the impact of oil prices on EOR activities by comparing the actual EOR oil production to that predicted by earlier Natl. Petroleum Council (NPC) reports. Although the lower prices since 1986 have reduced the number of EOR projects, the actual incremental production has been very close to that predicted for U.S. $20/bbl in the 1984 NPC report. Incremental oil production from CO2 flooding continues to increase, and now actually exceeds the predictions made for U.S. $20 oil in the NPC report, even though oil prices have been at approximately that level for some time.
Practical Procedure To Predict Cresting Behavior of Horizontal Wells
Authors: de Souza A. L. S. , Arbabi Sepehr , Aziz Khalid
Published: December 2007

Water and gas cresting in horizontal wells are important phenomena in reservoirs that have an aquifer or a gas cap. In practical situations, many reservoirs are produced under supercritical rates, and a breakthrough of the displacing phase becomes inevitable. At the beginning of a reservoir simulation study, it is desirable to make an estimate of the breakthrough time and the post-breakthrough behavior. Grid sensitivity runs are also required to obtain the appropriate gridblock sizes. An accurate representation of cresting behavior requires a very fine grid, which is not always practical. In this work, a procedure was developed to obtain accurate breakthrough times by use of just coarse grid simulations. The flow equations were written in dimensionless form, and important parameters affecting multiphase flow were identified. Simple correlations for a quick estimate of breakthrough time, maximum oil rate, and post-breakthrough behavior were derived on the basis of an appropriate set of dimensionless variables and an extensive number of simulation runs. The effects of gridblock size and grid pattern were investigated in detail. Effects of rate, mobility ratio, well drainage area, well height, and endpoints and shapes of relative permeability curves were also included. A procedure to derive pseudofunctions, either by numerical correlations or coarse grid simulations, is also presented. These pseudofunctions can be used to improve the performance of coarse grid simulations. An optimum grid pattern to start a reservoir simulation study is proposed. An application with real data shows that the correlations and procedures derived are reliable and accurate and can be used for quick estimates before starting a reservoir simulation study.
A Case Study in Scaleup for Multicontact Miscible Hydrocarbon Gas Injection
Authors: Jerauld G. R.
Published: December 2007

We describe the strategy and results of scaleup done to simulate a multicontact miscible hydrocarbon water alternating gas (WAG) injection process. To adequately model both oil recovery and solvent retention in WAG, one must model three-phase flow including gas trapping. Scaleup of the multicontact miscible gas process is particularly difficult because of the very fine-scale structure of the gas fingers and the miscible front. The case studied is a heterogeneous mixed wet reservoir with a transition zone down to an underlying aquifer. The objective was to develop pseudo relative permeability curves and other parameters that are suitable for running in a full-field limited compositional model with three hydrocarbon components.

Both history-matching and systematic approaches were used to generate pseudo relative permeability curves that reproduced results of high-resolution, fully compositional (FC) reference simulations. Dynamic pseudoization techniques were used to derive first guesses at pseudos, but required further calibration to reproduce reference simulations successfully. In matching incremental miscible gas/oil recovery timing and solvent retention, varying three-phase water relative permeability was much more effective than varying the mixing parameter.

The predictive capability of pseudos was tested for changes with respect to slug size, WAG ratio, and solvent enrichment. Pseudos derived for one pattern or cross section were tested in other patterns or cross sections. Pseudos worked well with respect to changes in WAG ratio, fairly well with respect to changes in solvent enrichment, and moderately well for changes in slug size. They were less robust with respect to changes in description.
Analysis of Hydraulic Fracture Closure in Laboratory Experiments
Authors: Dam D. B. van , Pater C. J. de , Romijn Remco
Published: December 2007

Conventional models of hydraulic fracture closure make assumptions about the fracture geometry and rock mechanical behavior. In this paper we present the results of scaled laboratory experiments. We show that deviations from conventional assumptions influence leak-off volumes, mechanical behavior, and pressure decline significantly. We discuss mechanisms that lead to these deviations from assumptions during fracture closure.
Integrating Pressure Data From Formation Tester Tools and DSTs To Characterize Deepwater Fields, East Kalimantan, Indonesia
Authors: MacArthur Jack , Vo D. T. , Palar Steve , Terry Albert , Brown Trevor , Hariyadi Hariyadi , May Ron
Published: December 2007

In the past 3 years, two significant commercial hydrocarbon accumulations in the deep waters of the Makassar Strait, Indonesia, were discovered. These fields are located approximately 16 miles northeast of the giant Attaka field in 1,400 to 3,400 ft of water.

To date, more than 40 exploration and appraisal wells have been drilled in both fields, and extensive pressure data have been collected by formation tester tools and drillstem tests (DSTs). The pressure data, used with other data such as seismic and well logs, have enabled us to characterize deepwater turbidite sand reservoirs.

In this deepwater environment, DSTs are used selectively and only with strong justification because of their prohibitive cost. Instead, the use of the pressure-testing tool is pushed to its limit to gain extensive data on pressure, rock, and fluid properties conventionally obtained by DSTs.

This paper will show how the deepwater reservoirs were characterized by means of pressure data from formation tester tools and DSTs to complement geological and seismic data interpretations. Reservoir characteristics such as fluid type, fluid contacts, reservoir connectivity, and sand geometry can be inferred from the pressure gradients and pressure transients. These data are used in constructing reservoir fluid-flow models for a field-development plan.
Formation Electrical Anisotropy Derived From Induction-Log Measurements in a Horizontal Well
Authors: Bang Jon , Solstad Arne , Mjaaland Svein
Published: December 2007

An existing theory describes how electrical anisotropy in the formation affects the response of resistivity logging tools. We have related this theory to the processing of logging while drilling (LWD) induction logs and are thus able to calculate the anisotropic resistivities directly from the logs.

The method has been demonstrated by application to logs from a horizontal well section. Anisotropy ratios of 2 to 5, and occasionally higher values, were obtained for this formation. We also addressed the accuracy of these numbers by using independent sets of input logs. The results indicate that the logs are influenced by factors like invasion, in addition to the anisotropy.

Our approach provides a fast and efficient computer algorithm. The output is calculated at the depths of the input logs; hence, the resulting anisotropy becomes a depth-dependent formation property.
A Fast and Direct Method of Permeability Measurements on Drill Cuttings
Authors: Egermann P. , Lenormand R. , Longeron D. , Zarcone C.
Published: December 2007

Permeability is one of the most important petrophysical parameters for reservoir characterization, but also one of the most difficult to obtain. Logs provide a good estimate of porosity and saturations, but the accuracy on permeability derived from nuclear magnetic resonance (NMR) is rather poor. So far, reliable values of permeabilities are obtained only from laboratory measurements on core samples for local measurements and well testing for a larger scale-averaged determination.

We present an original method for measuring the permeability of drill cuttings without any specific laboratory conditioning (cleaning, coating, etc.). A volume of approximately 100 cm3 of cuttings is placed in a pressure vessel. The cell is then filled with a viscous oil. The process of oil invasion into the cuttings always traps a certain amount of gas. When a pulse of pressure is applied on the cell, the oil enters into the cuttings thanks to the gas compressibility. The permeability is then derived from the dynamic of the oil invasion by using a simple model.

The method was tested by using various crushed-rock samples of known permeability. Excellent reproducibility and good agreement between cores and cuttings permeabilities were found for many decades of permeabilities. This method presents many advantages. The measurements can be performed in a few minutes, leading to the possibility of operating on site during drilling. The limitations of the method are related mainly to the size, the representativity of the drill cuttings, and the absence of the confining stress.

In developing this method, our purpose is not to replace core analysis but, rather, to provide additional quick and inexpensive information on reservoir characterization.
Timestep Selection During Streamline Simulation Through Transverse Flux Correction
Authors: Osako Ichiro , Datta-Gupta Akhil , King Michael J.
Published: December 2007

Streamline simulators have received increased attention because of their ability to effectively handle multimillion-cell detailed geologic models and large simulation models. The efficiency of streamline simulation has relied primarily on simulators' ability to take large timesteps with fewer pressure solutions within an IMPES formulation. However, unlike conventional finite-difference simulators, no clear guidelines are currently available for the choice of timestep for pressure and velocity updates. This has remained largely an uncontrolled approximation, either managed by engineering judgment, or by potentially time-consuming timestep size sensitivity studies early in a project. This is clearly related to the lack of understanding of numerical stability and to the lack of error estimates during the solution.

We propose a novel approach for timestep selection during streamline simulation based on three elements. First, we reformulate the equations to be solved by a streamline simulator to include all of the 3D flux terms—both aligned with and transverse to the flow directions. These transverse flux terms are totally neglected within the existing streamline simulation formulations. Second, we propose a simple grid-based corrector algorithm to update the saturation to account for the transverse flux. Third, and most importantly, we provide a discrete Courant-Fredrich-Levy (CFL) formulation for the corrector step that leads to a mechanism to ensure numerical stability through the choice of a stable timestep for pressure updates. This discrete CFL formulation now provides us with the same tools for timestep control as are available within conventional reservoir simulators.

We demonstrate the validity and utility of our approach using a series of numerical experiments in homogeneous and heterogeneous ¼ five-spot patterns at various mobility ratios. For these numerical experiments, we pay particular attention to favorable mobility ratio displacements, as they are known to be challenging to streamline simulation. Our results clearly demonstrate the role of the transverse flux and our proposed CFL formulation on the accuracy of the solution and on the appropriate choice of timestep across a range of mobility ratios. The proposed approach eliminates much of the subjectivity associated with streamline simulation, and provides a basis for automatic control of pressure timestep within full-field streamline applications.
The Disc Bit - A Tool for Hard-Rock Drilling
Authors: Plácido J. C. R. , Friant J. E.
Published: December 2007

This paper traces the development of a radically different design of drill bit, describing its concept, laboratory work, and the latest field trials.

Disc-bit technology is based on the single-rolling disc cutter. This cutter was first used successfully in rock on a tunnel-boring machine in 1956. By the early 1970s, virtually every rock-tunneling machine in the world had evolved from picks, tungsten carbide button cones, or multirow tapered cutters to the single-row disc. By then, practical field experience had demonstrated the superior performance of tunneling machines. Further, the Colorado School of Mines (CSM) began scientific studies and published data comparing the specific energy of excavation of various tools on the basis of full-scale laboratory testing. These studies clearly showed that the single-row disc cutter required less energy than conventional cutters used in roller cones to excavate a given volume of rock. With energy at the cutting face always a limited commodity, a lower energy requirement translated to a higher rate of penetration (ROP).

Not until the mid-1990s was the concept of the single-rolling disc cutter applied to drill bits. Very small—3¼-in. Mini-Disc™— cutters were evaluated at CSM and found to be extremely efficient and sufficiently robust to be used on drill bits as small as 7⅞ in. An evaluation of an 8½-in. disc bit was performed at the Gas Research Inst. (GRI) Catoosa Test Facility in Oklahoma. The U.S. GRI sponsored an effort to develop the concept through laboratory and field testing. Other field trials were sponsored by private and government grants, including the most recent test funded by a joint industry project (JIP) and managed by Petrobras.
Effect of Additives on the Acid Dissolution Rates of Calcium and Magnesium Carbonates
Authors: Taylor K. C. , Al-Ghamdi A. H. , Nasr-El-Din H. A.
Published: December 2007

A rotating-disk instrument was used to measure the dissolution rates of both calcite and dolomite rock samples in HCl solutions. The results of more than 60 experiments are reported in this paper. The effect of common acidizing additives on the rock dissolution rate is measured for different acids containing quaternary amines, polymer, surfactant, mutual solvent, iron-chelating additive, and dissolved iron. Measurements are made at 23 and 50°C for calcite and dolomite marble samples.

Marble samples from Turkey, Greece, and Italy were analyzed to find suitable reference materials. Marble composed of 100% calcite (calcite marble) as well as 91% dolomite (dolomite marble) was used and compared very well with previously published results. Results of rock dissolution rates with common acidizing additives showed significant differences.

1.5 vol% cationic acrylamide copolymer decreased the calcite and dolomite dissolution rates significantly. At 1,000 rpm, the calcite dissolution rate with 1.5 vol% polymer and 0.1 M (0.36 wt%) HCl had a value that was 11.4% of the value measured with 0.1 M of HCl alone. Polymer changed the acid/rock reaction from mass-transfer-limited to surface-reaction-limited with both calcite and dolomite. This surface effect is possibly caused by polymer adsorption. 10 vol% mutual solvent increased the acid dissolution rate by 9% for calcite and by up to 29% for dolomite. 5000 mg/L iron (III) resulted in surface deposition of iron (III) hydroxide for both calcite and dolomite. At low rotational speeds, this surface layer had an inhibiting effect on the dissolution rate. 2 vol% corrosion inhibitor decreased the calcite dissolution rate by approximately 9%. Citric acid at 12 g/L decreased the calcite dissolution rate by an average of 9%, possibly because of the formation of calcium citrate at the surface. 0.2 vol% nonionic surfactant had no significant effect on the acid dissolution rate of calcite.
Flow Patterns and Minimum Suspension Velocity for Efficient Cuttings Transport in Horizontal and Deviated Wells in Coiled-Tubing Drilling
Authors: Kelessidis V. C. , Bandelis G. E.
Published: December 2007

Coiled-tubing drilling (CTD), which has grown significantly in recent years, is normally associated with high-angle to horizontal and extended-reach wells. In these applications, however, hole problems become more troublesome because of inefficient cuttings removal. Among the many parameters affecting efficient cuttings transport in CTD are pump rates, well dimensions, fluid properties, solid sizes, solid loading, and hole inclination. Several attempts have been made to determine the optimum operating range of these parameters, but complete and satisfactory models have yet to be developed.

The purpose of this paper is as follows:

To provide a critical review of the state-of-the-art modeling for efficient cuttings transport during CTD. To present the critical parameters involved. To establish their range according to what is observed in practice. To propose a different approach for predicting the minimum suspension velocity. To describe the laboratory system that has been set up. The primary purpose of the flow system is to enable the gathering and publication of good-quality data that, together with previously published data, could further enhance our understanding of the flow of solid/liquid mixtures in annuli.
Study of the Effects of Pressure and Temperature on the Viscosity of Drilling Foams and Frictional Pressure Losses
Authors: Lourenço Affonso M. F. , Miska Stefan Z. , Reed Troy D. , Pickell Mark B. , Takach Nicholas E.
Published: December 2007

A discussion about horizontal foam-flow behavior in pipes and annular geometry under elevated pressures and temperatures is presented. The study is empirically based and covers the effects of foam quality, foam texture, pressure, temperature, and geometry of the conduit on the rheological response of foams.
Automatic History Matching of Geologic Facies
Authors: Liu Ning , Oliver Dean S.
Published: December 2007

The truncated pluri-Gaussian method for modeling geologic facies is appealing not only for the wide variety of textures and shapes that can be generated, but also because of the internal consistency of the stochastic model. This method has not, however, been widely applied in simulating distributions of reservoir facies or in automatic history matching. One reason seems to be that it is fairly difficult to estimate the parameters of the stochastic model that could be used to generate geological facies maps with the desired properties. The second is that because "facies type" is a discrete variable, it is not straightforward to apply the efficient gradient-based minimization method to generate reservoir facies models that honor production data. Nongradient methods, however, are too slow for large field-scale problems.

In this paper, the nondifferentiable history-matching problem was replaced with a differentiable problem so that an automatic history-matching technique could be applied to the problem of conditional simulation of facies boundaries generated from the truncated pluri-Gaussian method. The resulting realizations are consistent with both the geostatistical model of the observed facies and the historic production. Application of the method requires efficient computation of the gradient of the objective function with respect to model variables. We present an example five-spot water-injection problem with more than 73,000 model variables conditioned to pressure data at wells. The gradient was computed using the adjoint method, and the minimization routine used a quasiNewton algorithm. The objective function decreased more than 98% in 13 iterations.
Evidence and Implications for Significant Late and Post-Fold Fracturing on Detachment Folds in the Lisburne Group of the Northeastern Brooks Range
Authors: Bui T. D. , Brinton J. , Karpov A. V. , Hanks C. L. , Jensen J. L.
Published: December 2007

In exposed detachment-folded Lisburne Group carbonates, field evidence and statistical analysis suggest that a significant population of fractures postdate folding. Both prefold fractures and penetrative strain associated with peak folding are overprinted by late-folding and post-folding fractures. Late-folding fractures strike east/west, parallel to the fold axes. These, and the earlier structures, are consistently overprinted by pervasive late north/south extension fractures. Both east/west and north/south fracture sets have similar average and median spacings.

Statistical analysis of fold angle and fracture spacing indicates that, as the folds tighten, both the east/west and north/south fracture spacings increase by a factor of two or three and become slightly more variable. This behavior is opposite from that expected if the fractures were closely related to folding. It suggests that the two sets are similar to each other and are only weakly affected by the folding.

This weak genetic relationship between folding and formation of the most obvious fractures serves as an important example with major consequences for reservoir modeling. Complex genetic and timing relationships between fractures and folds may result in several fracture sets, each having different characteristics (e.g., size, amount of fill, and termination type). Unless recognized, this could result in inappropriate wellbore placement or inaccurate productivity and recovery estimates. Modeling of this fractured system, for example, showed permeability changes greater than 80%, depending on fracture fill, timing, and flow direction.
Operational Experience by Applying Direct Electrical Heating for Hydrate Prevention
Authors: Urdahl Olav , Børnes Atle Harald , Kinnari Keijo J. , Holme Ragnhild
Published: December 2007

The novel technique of applying electrical heat to prevent hydrate formation in multiphase pipelines has been applied successfully on the Norwegian continental shelf. The first pipelines in which direct electrical heating (DEH) was applied have recently been put into operation. DEH is based on applying electrical current through the steel wall of the pipeline, generating heat through wall resistance. By applying DEH, the fluid temperature can be maintained at greater than the hydrate equilibrium temperature (HET). Operational experience has proven that the concept is successful with regard to temperature control. It has been shown that the DEH system is capable of heating the pipeline inventory from the seabed temperature to one greater than the HET.

The DEH system installed on the Huldra-Veslefrikk condensate pipeline is described in detail here. This is an 8-in. pipeline with a length of 16 km. The application of the DEH system with respect to hydrate prevention and possible hydrate remediation is also discussed in detail.
Development and Applications of the Sustaining Integrated-Asset-Modeling Tool
Authors: Liao T. T. , Lazaro G. E. , Vergari A. M. , Schmohr D. R. , Waligura N. J. , Stein M. H.
Published: December 2007

Integrated Asset Modeling (IAM) is a process that combines reservoir, well, and surface-facility models to create a complete system for reservoir and well optimization. This methodology ensures that the interactions among all components are correctly simulated. To realize the full benefit of IAM models, it is critical that changing reservoir and well conditions are entered to keep the models up to date and valid. If an IAM model is not frequently and properly maintained to reflect new conditions, it will rapidly lose its value as it ceases to accurately predict well production rates and pressure drops in the system.

An application tool was developed to provide easy updating and maintenance of IAM models for production optimization, surface-network debottlenecking, and production allocation. This tool automates the routine tasks required to update and maintain large-scale IAM models. The unique feature of this tool is its ability to calculate well production rates in almost real time by feeding well operating parameters obtained from the SCADA system into updated well-performance models. These production rates can be used to allocate total volumes measured at gathering centers back to individual wells. In addition, engineers can keep track of well matching parameters, such as productivity indices or skins, in the process of automatically maintaining IAM models using the sustaining integrated asset modeling (SIAM) tool. Trends in these parameters can then be analyzed to diagnose potential well problems and select workover candidates. Application of this tool in business units (BUs) has consistently resulted in a 90% reduction in model maintenance and management time, a streamlined process to maintain and update IAM models, and an improvement in production-allocation accuracy. These improvements have constituted a step change in IAM model application effectiveness across asset teams within BP.