bluuebunny/crossref_metadata_2025 huggingface dataset:
A Reservoir Management Case Study of the Nahorkatiya Oilfield
Authors: Khataniar S.K. , Bora A. , Borah N.M.
Published: December 2007

The Nahorkatiya oilfield had an initial stock tank oil in place of about 200 MMm and has been on production since 1953. The field is a structural-stratigraphic trap formed by block faulting resulting in a number of individual reservoir blocks of various sizes. The reservoir crude is saturated and combination drive with varying degree of aquifer support has been the primary drive mechanism. Pressure maintenance by gas and water injection and limited water/polymer flooding have been in operation in the major blocks. Overall field recovery is 31%, although in a few blocks recovery as high as 46% has been achieved through secondary recovery measures. This paper presents the reservoir management strategies undertaken at various stages of development to optimize production profiles and ultimate recovery.

P. 569
Identification of Coal Cleats/Fractures Using 2D and 3D Imaging Computed
Authors: Kumar Rajesh , Rundwal V.C. , Das T.K.
Published: December 2007

This paper presents a comprehensive X-ray computed tomography (CT scan) study on coal samples recovered from different layers of a coal deposit in an R & D well drilled in the central-eastern part of India. The cleats and fractures in the coal seams have been identified using 2D and 3D CT images.

The cleats / fractures present in the coal scam have been categorized based on the variation in the type of material or fluid filling the cleatsl fractures. On the basis of the results of CT scan and gas content analysis, it has been possible to select layers for a suitable stimulation job like hydrofracturing, to produce methane gas. Effect of acid treatment on the material filling the cleats has also been studied using CT scan technique.

P. 597
High Pressure/High Temperature (HP/HT) Seals for Oil and Gas Production
Authors: Ray Thomas W.
Published: December 2007

The drilling and completion of wells between 15,000 and 20,000 feet vertical depth has been actively pursued since the early 1950's because of the increased production capacities associated with these deeper wells. The high temperatures and high pressures inherent to this type environment, however, require special equipment to withstand the demands of the severe conditions to which the equipment will be subjected.

Selecting seals or sealing systems for oil and gas production necessitates a comprehensive knowledge of the chemistry of both the seal material(s) and the conditions of the environment in which the seals will be used. Understanding the unique characteristics of viscoelastic response is the key to understanding elastomers in general and applying them to specific uses.

This paper will discuss elastomer usage as sealing media in the oilfield; specifically, the use of polymeric seal materials will be followed from their usage in the oilfield from 1977 to the present and their evolution to the elastometric element packages that have been developed for today's needs in traditional as well as in severe service and high pressure/high temperature (HP/HT) applications. Of particular interest will be testing to which the newly developed seal element packages have been subjected, including the testing that was conducted in a deep well simulator.

Case histories will support the enhanced capabilities of the new generation of polymeric seal assemblies.

In addition to the new generation of elastometric sealing packages, composite sealing materials have also been developed for certain applications in which elastomeric materials have not been able to provide long-term integrity. Progress being made in this area will also be discussed.

P. 603
Injectivity Decline in Wells with Nonuniform Perforation Properties
Authors: Hofsaess T. , Kleintz W.
Published: December 2007

Nonuniform perforation properties and permeability variations close to the wellbore introduce heterogeneities which affect the injectivity decline in water injection wells. We present a method to calculate these effects and derive results for a simple model which incorporates the dependence of the water- quality-ratio on the entrance porewidths. Common degrees of heterogeneity may lead to significant changes in the injectivity decline, which cannot be described by conventional models of uniform wells. Early damage rates may be orders of magnitude larger than expected and wells with large initial skins are prone to having their half-lifes within this early region. Due to the resulting nonlinearities, extrapolations from test-injections may lead to wrong conclusions and it is usually not possible to predict the half-life by the conventional use of a single value for the water-quality-ratio.

P. 631
Field Application of Gelling Polymers in Saudi Arabia
Authors: Nasr-El-Din H.A. , Bitar G.E. , Bou-Khamsin F.I. , Al-Mulhim A.K. , Hsu J.
Published: December 2007

H.A. Nasr-El-Din, SPE, G.E. Bitar, SPE, F.I. Bou-Khamsin, A.K. Al-Mulhim, SPE and J. Hsu, SPE, Saudi Arabian Oil company (Saudi Aramco)

High water production causes major economic and operational problems for several reasons. It decreases oil production, and results in large amounts of produced water that need to be disposed. It also requires increased capacity of water separation and handling facilities. Other production related problems include high corrosion rates and increased tendency for emulsion and scale formation. Therefore, there is a need to reduce water production. Several mechanical and chemical methods are available for water shut-off treatment. However, the choice of a specific treatment depends on the source of water, well characteristics, and cost.

Water shutoff treatments using chemical means include injection of a gelling solution that forms a gel at reservoir conditions. Three main gelling systems are available to conduct water shutoff treatments: a water-soluble polymer with a cross-linker, phenol-formaldehyde resin, and sodium silicate gels. Based on extensive lab studies, two gelling systems were field tested in Saudi Arabia during the last few years. Both gelling systems were applied in a carbonate reservoir. The reservoir temperature is 220-240 F and formation water has total dissolved solids ranging from 45,000 to 200,000 mg/l. The first gelling system consisted of a polyacrylamide polymer, acetate and a retarder. This system was applied in two wells as a means to reduce water production due to coning and bottom water. The second gelling system consisted of sodium silicate with intemal and extemal activators. This system was applied in a well with a high permeability streak.

Several operational and quality control problems were encountered during and after field applications. This paper discusses these problems in detail and recommends modifications to these systems to avoid operational problems encountered in the field. Advantages and disadvantages of using several gelling systems are also highlighted.

P. 133
Polymer/rock Interactions in Polymer Treatments for Water-cut Control
Authors: Chiappa Luisa , Mennella Aniello , Burrafato Giovanni
Published: December 2007

In this paper we study the adsorption of polymers bearing differently charged groups onto solid surfaces of siliceous nature. By means of static adsorption tests we show that the adsorption is dominated by the electrostatic interactions between the polymer molecules and the solid surface. We also show that both lithology and brine composition can strongly influence the adsorption behavior; such effects must be therefore carefully assessed before applying these treatments in the field.

P. 161
Using an Analytical Decline Model to Characterize Naturally Fractured Reservoirs
Authors: Baker R.O. , Spenceley N.K. , Guo B.
Published: December 2007

Effective fracture spacing is critical to the design of waterfloods and CO2 floods in naturally fractured reservoirs. Decline rate data with imbibition data can be simply combined to estimate effective fracture spacing. This paper describes how carefully designed laboratory imbibition experiments were scaled to the field and how these simple observations were used to estimate fracture spacing for a large naturally fractured reservoir. Fracture spacing was also independently estimated by horizontal well cores. There was excellent agreement between the decline rate / imbibition spacing calculations and that obtained from the horizontal well cores.

P. 205
Experimental Investigation of Scaling Factors that Describe Miscible Floods in Layered
Authors: Peters Bradley M. , Zhou Dengen , Blunt Martin J.
Published: December 2007

We performed miscible flooding experiments in a layered model. The model was composed of glass beads, with two horizontal layers constructed from beads of different sizes. The miscible fluids used were water and brine. We conducted experiments in two models: a long model and a short model. One fluid was dyed and injected at different flow rates. Production profiles were monitored by weighing the effluent. Pictures of the displacement process were recorded on video camera.

We studied how recovery was affected by the gravity number, which quantifies the ratio of gravity to viscous effects on the displacement process. The behavior was investigated as a function of two gravity numbers: Ng, which is a ratio of the vertical buoyancy force to the horizontal viscous force; and Ng* which is the ratio of the time taken for fluid to move horizontally under viscous forces to the time taken to move vertically under buoyancy forces.

We show that when viscous and gravity forces compete (such as injecting less dense fluid into a system where the lower permeability layer is on top), recovery improves with increasing gravity number (Ng or Ng*), even in the regime where gravity would dominate in a homogeneous system. Gravity can thus be used to improve sweep efficiency in heterogeneous media.

By comparing our results from the long and short models we arrive at the following surprising conclusion regarding the two gravity numbers: for unfavorable mobility floods (injecting a less viscous fluid) Ng* best describes recovery, whereas for favorable mobility floods Ng best characterizes the behavior. An explanation based on the pressure distribution in a layered system is proposed.

P. 211
Two-Phase Flow Property Modifications by Polymer Adsorption
Authors: Zaitoun A. , Bertin H. , Lasseux D.
Published: December 2007

The ability for polymers or weak gels to reduce selectively the relative permeability to water with respect to the relative permeability to oil or to gas is a unique property well documented but poorly understood. To better understand two- phase flow property changes induced by polymer adsorption, an original experimental set-up was designed that enabled profile saturation check inside the core by gamma rays, material balance, pressure drop and direct measurement of the capillary pressure during displacement of oil by water. Relative permeability curves were computed with the measured data as input into a specially designed software (FISOLE).

Experiments were run first with a naturally water-wet sandstone (Vosges sandstone), then with the same type of core previously treated with silane to make it oil-wet. Main results obtained after polyacrylamide adsorption are:Disproportionate relative permeability modification is observed both in water-wet and in oil-wet cores.The polymer induces an increase in water irreducible saturation.The polymer induces an increase in the capillary pressure.After adsorption in the oil-wet core, the core becomes water-wet as attested by the inversion of the capillary pressure sign and the strong reduction in residual oil saturation.

All these results can be interpreted in terms of "wall effects", i.e. an adsorbed polymer layer of significant thickness is formed on pore walls. Comprehensive pictures of end point pore situations are provided.

P. 285
Pore-scale Mechanism for Selective Permeability Reduction by Polymer Injection
Authors: Mennella Aniello , Chiappa Luisa , Bryant Steven L. , Burrafato Giovanni
Published: December 2007

In this paper we discuss a pore-scale picture of the mechanism underlying the selective permeability reduction caused by the adsorption of a polymer layer in a water wet porous medium. Our analysis is based on the use of physically representative model of the porous medium, which allows us to estimate directly the expected permeability reduction. Comparison of model predictions with coreflood experimental data has revealed that the selectivity in permeability reduction cannot be explained if the polymer layer is modeled as a rigid, impenetrable layer. This result is consistent with the suggestion that swelling-shrinking phenomena of the adsorbed polymer later is responsible for the selectivity in the permeability modification induced by these treatments.

P. 323
Effect of Relative-Permeability Modifier Treatments in a Sandstone-Layered System and
Authors: Dalrymple E. Dwyann , Brown David
Published: December 2007

By using chemical treatments in attempts to reduce the volumes of water produced from hydrocarbon-bearing strata, well operators face the risk of damaging productive intervals. To avert this problem, well operators often apply special placement techniques, (such as the use of the dual-injection technique and multiple-packer assembles) in attempts to focus water shutoff treatments into areas of interest. The special placement techniques require significant additional costs involving workover rigs, coiled-tubing units, multiple pumping units, tools, packers, and so on. Even when these precautions are taken, the chemical treatment may still enter the productive interval through any number of avenues, including the interzonal, communication, packer leaks or channels behind the pipe.

The oil and gas industry is inherently attracted to relative permability modifiers (RPMs) because they have the potential to reduce the relative risk factors involved when conformance water-management treatments are performed on active, hydro-carbon-producing wells. The term RPM has been misused at times by being used to refer to porosity-fill sealants (such as metal-complexed polyacrylamide systems). Although organic, water-based systems may preferentially achieve deeper penetration into water-saturated strata than into hydrocarbon strata, those systems still result in the forming of sealants. The ideal RPM should reduce the effective permeabilit6y to water with no effect on the effective permeability to oil.

The RPM materials available to the industry today are not ideal. These materials actually affect the effective permeability to both water and oil. The difference between and RPM and a sealant is that the RPM reduces the effective permeability to water more significantly than the effective permeability to oil.

This paper discusses the results of testing two currently available RPMs through porous rock media. The testing includes evaluation of the RPMs in a layered system(high-permeability streaks of water though hydrocarbon-bearing strata) and evaluations of the RPMs in a homogeneous system with varying degrees of water saturation (transition zone between oil and water-bearing strata).

P. 345
Large-Volume Foam-Gel Treatments to Improve Conformance of the Rangely CO2
Authors: Hughes T.L. , Wilson A. , Davies S.N. , Friedmann F. , Johnson D. , Hild G.P.
Published: December 2007

Large-volume foam-gel treatments can provide a cost-effective method to achieve in-depth conformance improvement in fractured reservoirs. The applicability and cost-effectiveness of the approach depends on the availability of a cheap source of gas, the efficiency with which the foam can be placed into the high permeability thief zone(s) and the effectiveness of the gelled foam barrier in diverting reservoir drive fluids to improve oil recovery.

This paper reviews progress in the application of large- volume CO2-foam-gel treatments to improve conformance in the Rangely Weber Sand Unit (RWSU), Colorado. The design, implementation, and evaluation of a series of 35,000-45,000 bbl injector well treatments is described. The first treatment was reported in SPE paper 38837. The objectives of this paper are to provide an update on the production response of the first treatment, to report on the status of the second and third treatments, and to describe new developments which increase the cost-effectiveness of the system.

We emphasize the importance of candidate well/pattern selection and evaluation to characterize the conformance problem and the main rapid communication trends between the injector and its associated producer wells. Prior to implementing the main treatment, a program of injector well tests is used to evaluate the flow characteristics of the thief zone(s), and the optimum foam injection strategy. The delayed gelation kinetics of the system are designed to optimize foam generation and placement, to ensure foam stabilization before the end of the pump period and to generate a strong and robust gelled foam barrier after placement.

The procedures used to determine treatment effectiveness are described. From the injector well viewpoint, changes in water and CO2 injectivity, and the extent and longevity of near well bore diversion after the treatment is given by a series of injection profile surveys and pressure fall-off tests. High frequency pre- and post-treatment production data are used to evaluate production response and incremental oil recovery. Finally, we discuss the cost-effectiveness of foam-gel treatments relative to polymer gels.

P. 445
Measurement of Three Phase Relative Permeability during Gravity Drainage using CT
Authors: Sahni Akshay , Burger Jon , Blunt Martin
Published: December 2007

We measured three phase relative permeabilities for gravity drainage using a dual-energy medical CT scanner modified to scan vertical cores. Independent measurements of two saturations as a function of time and distance along the length of the core were made from which relative permeabilities were found. Three phase (air/oil/water) gravity drainage experiments were performed on systems with different spreading coefficients and at different initial conditions. Experiments were run on both consolidated and unconsolidated porous media. The results were compared to measurements of three phase flow in capillary tubes, micromodels and to predictions from network modeling.

We find that at low oil saturation kro for hexane and octane as the oil phase. This functional form of relative permeability is consistent with the drainage of oil layers. wedged between the water and gas in crevices of the pore space. For decane, which is non-spreading, the layer drainage regime was not observed. At higher oil saturations kro with a for spreading and non-spreading systems. Within the scatter of the experimental data, oil and water relative permeability are functions only of their own saturations and independent of initial conditions.

P. 11
Relative Permeability Curves: The Influence of Flow Direction and Heterogeneities.
Authors: Crotti M.A. , Rosbaco J.A.
Published: December 2007

This paper presents results that highlight some aspects not often considered when dealing with experimental relative permeability curves in heterogeneous media, a very common situation in natural sandstone samples.

When comparing curves obtained from the same core sample as a result of horizontal and vertical floodings, they show a large difference in residual oil values and in the general displacement performance. The information thus gathered indicates a systematic tendency towards notably lower residual oil in the case of vertical floodings.

These results are significant because of the large number of cases of vertical flooding occurring throughout the productive life of a reservoir, such as crossflow among strata of different permeabilities, predominantly segregate flow, expanding gas cap, flow from basal aquifers, etc. This is the reason for contesting the standard procedure of always using the same single set of relative permeability curves that, in practically all cases, are determined by horizontal flow.

Based on the results presented herein, it is suggested that the end points used in order to describe the different reservoir flow and production models be obtained using horizontal and vertical flooding, as well as by imbibition and capillary pressure tests.

P. 39
Foam Flow in Heterogeneous Porous Media: Effect of Crossflow
Authors: Bertin H.J. , Apaydin O.G. , Castanier L.M. , Kovscek A.R.
Published: December 2007

Previous studies of foam generation and transport were conducted, mainly, in one-dimensional and homogeneous porous media. However, the field situation is primarily heterogeneous and multidimensional. To begin to bridge this gap, we have studied foam formation and propagation in an annularly heterogeneous porous medium. The experimental system was constructed by centering a 5.0 cm diameter cylindrical Fontainebleau sandstone core inside an 8.9 cm acrylic tube and packing clean Ottawa sand in the annular region. The sandstone permeability is roughly 0.1 d while the unconsolidated sand permeability is about 7 d. Experiments with and without crossflow between the two porous media were conducted. To prevent crossflow, the cylindrical face of the sandstone was encased in a heat-shrink Teflon sleeve and the annular region packed with sand as before. Nitrogen is the gas phase and an alpha olefin sulfonate (AOS 1416) in brine is the foamer. The aqueous phase saturation distribution is garnered using X-ray computed tomography.

Results from this study are striking. When the heterogeneous layers are in capillary communication and cross flow is allowed, foam fronts move at identical rates in each porous medium as quantified by the CT-scan images. Desaturation by foam is efficient and typically complete in about 1 PV of gas injection. When cross flow is prohibited, foam partially plugs the high permeability sand and diverts flow into the low permeability sandstone. The foam front moves through the low permeability region faster than in the high permeability region.

P. 255
Foam Propagation on Semi-Reservoir Scale
Authors: Vassenden F. , Holt T. , Solheim A.
Published: December 2007

Foam propagation in co-injection is studied in a 10 m long flow apparatus, equipped with pressure ports and fluid sampling valves for every 1 m. The data are compared to the result of a foam flooding experiment in a core scale flooding experiment with the same porous medium. The core scale experiment was simulated with a numerical foam simulator model.

The propagation experiments on the 10 m scale revealed that the foam front propagated significantly slower than the injected fluid front. It appeared that foam propagation was not limited by surfactant transport, but was delayed due to segregation of gas and surfactant solution, and by the presence of oil in the porous medium.

P. 301
A Promising Hydrophobicaly-Modified Guar for Completion Applications
Authors: Young N.W.G. , Williams P.A. , Meadows J. , Allen E.
Published: December 2007

Current demands for greater well productivity require development of less damaging completion and stimulation fluids. This paper examines a hydrophobically modified hydroxybutyl guar (HMHBG) which shows improved properties over native guar, hydroxypropyl guar (HPG) and hydroxybutyl guar (HBG). HMHBG possesses I-2(w/w)% CI6 alkyl chains randomly distributed. The average molecular weight of the HMHBG is 2.2 million compared with 1.6 million, 2.0 million and 2.7 million for guar, HPG and HBG respectively. This paper presents the shear and extensional flow behaviour and viscoelastic characteristics of the four polymers in solution, and in the presence of the anionic surfactant sodium dodecyl sulphate (SDS).

Experimental results showed that the extensional viscosity of HMHBG was up to 100 times greater than the corresponding shear viscosity. The zero shear viscosity is 8 times greater for HMHBG and 3 times greater for HBG compared to native guar. Addition of SDS resulted in a 10 fold increase in solution viscosity of HMHBG at intermediate surfactant concentrations, however, the non hydrophobically modified polymers solutions showed no observed change. This was attributed to the promotion of intermolecular associations due to the preferential binding of the surfactant to the hydrophobic regions.

These results indicate that greater viscosity control can be achieved by use of hydrophobically modified guars which may have advantages over native guars for completion and stimulation applications.

The high extensional viscosity of HMHBG may reduce leakoff, thus reducing potential formation damage in gravel packing and hydraulic fracturing applications. The higher viscosities at low shear rates can improve solids transport. Furthermore the hydrophobically modified polymers minimize the problem of shear degradation because the intermolecular associations, although broken down by high shear conditions, are reformed when the shear stresses return to lower values. Since the molecular weight and the actual hydrodynamic volume are much smaller than for traditional polyacrylamide and scleroglucan molecules, these polymers should also minimize pore clogging, and thus give improved cleanup and return permeabilities.

P. 463
Matrix-Fracture Mass Transfer
Authors: Gabitto Jorge F.
Published: December 2007

An important mechanism in oil recovery from fractured reservoirs is multicomponent gas-liquid mass transfer. A model is presented to study effect of multicomponent, multiphase mass transfer from a porous matrix to fractures including the effects of capillarity and interfacial tension gradients. A custom made two dimensional simulator has been developed for this purpose. The simulator has allowed us to study mass transfer from a matrix block to a fracture when transport occurs: within single phase, across a partially immiscible phases along a single tie-line and across several partially immiscible tie-lines. The effects of enrichment, gravity orientation, capillarity and residual water saturation on recovery have been studied. Our results show that diffusion alone cannot explain the extent of recovery.

P. 471
A Model for Tracer Flow in Heterogeneous Porous Media
Authors: Numbere D.T. , Erkal A.
Published: December 2007

A tracer model utilizing scale dependent dispersion coefficient applicable to heterogeneous porous media is presented. Being a fractal model, it integrates the effects of the many length scales of heterogeneities and can be used for the prediction of fluid flow and mixing during tracer and unit mobility miscible displacements. A random field theory was used to describe the dispersion coefficient in terms of a scaling parameter. The resulting convection-dispersion equation with the scale-dependent dispersion coefficient was solved numerically by a Dual Reciprocity Boundary Element (DR-BEM) technique to generate type-curves of tracer concentration with time. This can be used in conjunction with data from field tracer tests, to determine the characteristic value of representative of a field. A simple equation is provided to calculate the dispersion coefficient at any length scale in terms of the so determined and the field velocity correlation function. The accuracy of the model was tested by comparing its results for a range of values representing asymptotically Fickian dispersion with analytical results and excellent agreement was obtained.

P. 37
Uncertainty Handling Through Scenario-Based Reservoir Modelling
Authors: Bentley M. R. , Woodhead T. J.
Published: December 2007

Quantitative forecasts of sub-surface productivity underpin prospect appraisal and development planning, yet the uncertainties intrinsic to those forecasts are difficult to predict. Moreover, the uncertainties invariably remain commercially significant throughout the field life cycle. This paper supports a case for the application of process-based logic to uncertainty handling, expressed in terms of independent, deterministically designed, concept-based development scenarios. Case studies of scenario-based logic are given, applied to 3-D reservoir modelling and simulation for a new, ‘greenfield’ site in Oman and a mature, ‘brownfield’ asset in Thailand. In both cases, uncertainty ranges are generated which provide a quantitative link between subsurface unknowns and commercial decisionmaking.
Application of Lévy Random Fractal Simulation Techniques in Modelling Reservoir Mechanisms in the Kuparuk River Field, North Slope, Alaska
Authors: Gaynor Gerard C. , Chang Eric Y. , Painter Scott L. , Paterson Lincoln
Published: December 2007

Incorporating a suitable level of heterogeneity into reservoir simulations is necessary for accurate prediction of production rates and final recoveries. Spatial correlation of petrophysical properties, particularly permeability extrema, exerts a profound influence on flow underlying reservoir displacement and depletion processes. Common modelling techniques are founded on Gaussian assumptions for statistical distributions. Such Gaussian-based approaches can inadequately model the permeability extrema that can dominate reservoir performance. However, optimal reservoir management strategies at the Kuparuk River Field require that significant efforts be made to correctly model reservoir behaviour.

This study utilises a new method, Lévy fractal simulation, for interpolating permeability at a former gas injection area now being targeted for oil production. The main producing interval is a diagenetically and mineralogically complex clastic unit. The diagenetic complexity causes difficulties in the lateral modelling of large changes in petrophysical properties observed in near-vertical wells, particularly permeability. Prior efforts at modelling the movement of gas, at typical interwell scales, have met with limited success. In this study, the Lévy technique employs automatic calibration with log and core data for the interwell interpolation of the spatially complex reservoir properties. The Lévy fractal simulations preserve the sharp jumps in reservoir properties observed at stratigraphic boundaries and within reservoir sub-zones. The spatially correlated petrophysical properties are consistent with geologic experience.

A fine-scale permeability model incorporating well conditioning data was built using the Lévy fractal interpolation technique. This model encompassed not only the gas injection area but drillsite patterns immediately adjacent. The model preserves the geometry of the reservoir units so that truncation and onlap relationships are preserved. The permeability extrema in the model are characterised by lateral continuities extending over many grid blocks away from control locations. Porosity was modelled using sequential Gaussian simulation (SGS) in which well porosity logs were used as the primary conditioning data, and the modelled permeability used as secondary conditioning data. The fine-scale model was then used as input in an upscaled dynamic simulator built to test reservoir mechanisms. The model was also useful for prognosing porosity and permeability at proposed well locations. Early drilling results indicate that substantial quantities of producible oil remain in the former gas injection area.
A New Method for the Fast Estimation of Reservoir Performance
Authors: Kuhn J.C.
Published: December 2007

Recent advances in applications of geostatistics to reservoir characterization have produced increasingly sophisticated geological models which have put considerable demands on the engineer's ability to do rapid reservoir performance evaluation. With this motivation in mind, a new method for fast reservoir simulation based on an unconventional formulation has been developed. This formulation has flux-based unknowns, in contrast to more conventional approaches which typically have pressure-based unknowns. For a useful range of conditions, the flux-based unknowns experience little or no variation over time throughout most of the reservoir domain, enabling fast simulations of fluid movement in the reservoir. In conjunction with iterative solvers that dynamically adapt to conditions in the reservoir, this formulation has been used to create a new simulator, designated as FMF (for Flux-based Multi-phase Flow). The FMF algorithm includes a rigorous mass conservation scheme that maintains accurate material balance throughout the entire simulation. Studies of overall accuracy and computational efficiency for a series of case studies have been carried out with the simulator. These studies are based on comparisons with Eclipse, with all computations done on a common platform to facilitate CPU timing studies. For the cases considered, these studies have revealed that the FMF algorithm is approximately one order of magnitude faster than Eclipse, and produces similar results.

P. 171
Modeling Non-Equilibrium Mass Transfer Effects for a Gas Condensate Field
Authors: Wu Wei , Wang Peng , Delshad Mojdeh , Wang Chong , Pope Gary A. , Sharma Mukul M.
Published: December 2007

To assess the effect of non-equilibrium mass transfer on the productivity of a single well producing from a gas condensate field, a model incorporating non-equilibrium mass transfer effects was implemented into an equation-of-state (EOS) compositional reservoir simulator developed at The University of Texas at Austin.

A correlation from the literature was used to account for the effect of variables such as gas velocity and diffusion coefficients on the mass transfer coefficient. However, no mass transfer data were available for gas condensates, so a sensitivity study on the mass transfer coefficient was performed. Several simulations have been performed to evaluate the effects of the non-equilibrium mass transfer on the flow behavior in the region near the wellbore. The results from these runs were compared with those obtained under the local equilibrium assumption. Such comparisons reveal that non-equilibrium phase behavior lead to a reduction in the condensate saturation in the region near the wellbore. The mole fractions for light and heavy components in the oil phase are noticeably different. In the high velocity layers, these differences become more significant. In general, non-equilibrium effects lead to slower reductions in well productivity due to the fact that condensate dropout was reduced near the wellbore.

P. 203
Pitfalls of Injection/Falloff Testing in Coalbed Methane Reservoirs
Authors: Hopkins C.W. , Frantz J.H. , Flumerfelt R.W. , Spivey J.P.
Published: December 2007

Analysis of numerous injection/falloff tests in the field, primarily on coalbed methane wells, has led to a better understanding of the requirements for proper injection/falloff testing. Because most of the formations do not flow prior to testing, test design is difficult and many of the testing procedures must be modified during the test itself. If a testing program is not carefully designed and implemented, erroneous results for permeability and skin factor can be obtained, even though the analysis results appear reasonable.

This paper outlines some general guidelines for injection/falloff testing of coalbed methane and other low permeability reservoirs. Using several field-based examples, potential analysis pitfalls are highlighted including 1) injection above fracture pressure, 2) non-stable reservoir pressure prior to testing, and 3) a poor connection between the wellbore and reservoir. Any of these conditions may result in pressure responses which appear analyzable, but which give misleading or erroneous results.

P. 197
Laboratory Investigation of Injectivity Losses During WAG in West Texas Dolomrites
Authors: Kamath J. , Nakagawa F.M. , Boyer R.E. , Edwards K.A.
Published: December 2007

This study reports injectivity data for the different flow zones present during a Water-Alternating-Gas (WAG) flood. The experiments were carried out on four rock types sampled from the Grayburg dolomite formation in West Texas. We used liquid CO-water, toluene-liquid CO-water and crude oil-liquid CO-water systems to isolate mechanisms and to address wettability concerns.

We found that the injectivity of the chase water zone was comparable to the initial waterflood injectivity, and increased as the trapped CO dissolved. The injectivity of the CO-rich zone was significantly higher than the initial waterflood injectivity. Ambient condition toluene tests and reservoir condition crude tests gave similar results for the water and CO zones. However the crude oil, even prior to any CO injection, exhibited a strong tendency to plug the core samples. We were unable to restore permeability in the plugged up core samples by continuous flushing of different solvents.

P. 345
Use of Mixed Surfactants to Improve Mobility Control in CO2 Flooding
Authors: Tsau Jun-Slung , Yaghoobi Hossein , Grigg Reid B.
Published: December 2007

The potential for using mixed surfactants at low concentration to improve mobility control in CO flooding was evaluated in laboratory experiments. We examined various mixed surfactant systems, such as alpha olefin sulfonate and ethoxylated alcohol sulfate, through foam durability and flowing tests.

In foam durability tests, we used a high pressure device to assess the stability of CO-foam bubbles and other pertinent properties. In flowing tests, we used a composite core to measure the flowing properties of foam in two differing sections of permeability.

Our foam durability test results showed that some mixed surfactants exhibit either comparable or better foam stability than the foam generated using the individual surfactants. During the foam flowing tests, we observed substantial mobility reduction of CO with mixed surfactants at very low concentration. Depending on types of surfactant mixed, some mixed nonionic and anionic surfactants demonstrate a better mobility reduction than that produced by an anionic surfactant alone. Additionally, improved mobility dependence on rock permeability is observed for most of the mixed surfactants.

P. 355
Compositional Simulations of a CO2 Flood in Ford Geraldine Unit, Texas
Authors: Malik Mohammad A.
Published: December 2007

The Ford Geraldine Unit (FGU), in Reeves and Culberson Counties, West Texas, produces from the Ramsey Sandstone in the upper Bell Canyon Formation. After primary depletion, a major portion of the reservoir was waterflooded in stages from 1969 to 1980 and is currently under a maturing CO flood that was started in 1981. However, because of high initial water saturation of 47.7% and some aquifer encroachment, the structurally low areas in the northeastern part of the reservoir were producing at very high water cut when the primary recovery approached its economic limit in 1968. As a result, this area responded very poorly to waterflood and no significant production has since been realized from this part of the unit. An estimated 10.1 MMSTB of the 12.9 MMSTB original oil in place (OOIP) remains in the reservoir in this area.

This paper presents results of a study in which advanced geologic, geophysical, and engineering reservoir characterization techniques have been applied to this part of the reservoir as a demonstration area for enhanced recovery. A conditionally simulated Stochastic-permeability-distribution model has also been developed. Compositional simulations were performed for CO flood using stochastic and layered permeability distributions and conservative estimates of fluid saturations.

Results indicate that a minimum of 10% of remaining oil in place (ROIP) can be recovered at breakthrough. Despite very high postwaterflood water saturations, the producing water cut gradually declines because of increase in hydrocarbon mobility as the injected CO dissolves in the oil. An important observation is that compositional simulations indicate significant incremental recovery after breakthrough. At the permissible gas-oil ratio (GOR) of 30 MSCF/STB, recovery of over 30% of ROIP is achievable from the demonstration area.

P. 375
Modeling Nonlinear Phenomena
Authors: Kapur Loveena , Lake Larry W. , Sepehrnoori Kamy
Published: December 2007

This paper discusses various ways to quantify nonlinear relationships, in general, and an application of the procedures explored to the Atlas of Major Texas Oil Reservoirs database compiled by The University of Texas Bureau of Economic Geology.

A system is nonlinear if the relationship between its input and output cannot be described by a straight line. Detecting such a relationship is confounded when random noise is present in the system's output. Most relationships in petroleum engineering are nonlinear. The first part of this work describes a numerical experiment that uses a known but noisy nonlinear function to generate system input. The function contains a parameter that specifies the degree of nonlinearity and an independent white noise component. For varying degrees of nonlinearity and noise we investigate which of three techniques, conventional linear regression, the optimal transform method, and a neural network, best reproduce the input-output response. As expected, linear regression works best (in the sense that it reproduces the known function) when nonlinearity is small. Optimal transforms work best for moderate amounts of noise and for nonlinear functions. No technique works, regardless of how nonlinear it is, when the system is dominated by noise.

The optimal transform procedure is illustrated by correlating oil recovery efficiencies reported in the Atlas of Major Texas Oil Reservoirs database. The results are obtained by performing the procedure on data sets that have been preprocessed by dividing according to drive mechanisms and/or reservoir classes.

P. 457
Polyethylene Lined Tubing in Rod Pumped Wells
Authors: Sirgo Eric C. , Gibson Edward D. , Jackson William E.
Published: December 2007

Although High Density Polyethylene (HDPE) lined tubing has been used regularly as a corrosion barrier to protect tubing in water injection applications, it has had limited application as a corrosion/wear barrier in rod pumped wells. With a goal of reducing well failures due to rod/tubing wear and internal tubing corrosion, polyethylene lined (poly-lined) tubing was installed in 17 rod pumped wells in the McElroy Field in Crane, Texas. It was assumed that the liners would provide sufficient reductions in friction between the rods and tubing to reduce wear, and that the sealed system would further reduce failures due to corrosion on the tubing strings. The pilot test shows that the wells equipped with the polyethylene liners have outperformed their previous failure histories. Overall the average runtime without an internal wear/corrosion related failure to the tubing and without a wear related failure to the rods has increased approximately 400% among the subject wells. Runtime including all failures has increased over 300%. In addition the system has demonstrated that used tubing can effectively be used in a field where traditionally new tubing had been purchased to extend run times. In those cases where artificial lift designs were not changed after the poly-lined tubing was installed, there was a measurable reduction in the Polished Rod Load Range, Balanced Torque and minimum stresses in the bottom of the rod string. Overall average failure ratio for the pilot wells has declined dramatically from 4.3 to.59.

P. 535
Fixed-Base Platform Concepts in Deep Water for the Gulf of Mexico
Authors: Campo J.J. , Serpas R.J.
Published: December 2007

This paper presents structural concepts utilized and proposed for deep water applications (400 ft. to 1000 ft.) in the Northern Gulf of Mexico.

Concepts presented include tripods, lifted and launched jackets and main and skirt piled platforms.

General analysis procedures for in-place platform design including dynamics and spectral fatigue are covered. Regulatory requirements and their effect on design and operation requirements are also discussed.

P. 185
A Study of Slug Characteristics for Two-Phase Horizontal Flow
Authors: Marcano R. , Chen X. T. , Sarica C. , Brill J. P.
Published: December 2007

Understanding the behavior of multiphase flow in pipelines is an important factor in the safe and economical design and operation of multiphase systems. Slug flow is a common and very complex occurrence in these pipelines.

Sixty-two slug-flow tests were conducted over varying combinations of gas and liquid flow rates. A total of 25,975 slugs were generated, ranging from 23 to 1145 slugs per test. The flow loop consisted of a 3.068-in diameter, 1378-ft long horizontal flowline, a two-stage air compressor, a centrifugal pump, and a data acquisition system utilizing LabVIEW™ with a Macintosh II ci computer.

The primary data collected during the experimental tests consisted of continuous readings of pressures, temperatures, flow rates, and liquid holdup. Processing of this data yielded slug translational velocities, slug lengths, pressure drops, slug length distribution, and slug frequency. Analysis of the results showed that the slug length distribution followed a Lognormal pattern. New correlations were developed for slug liquid holdup, film liquid holdup, slug translational velocity, slug frequency, average slug length and design slug length.

Using the data from this study, the new correlation for slug liquid holdup was compared with predictions from the correlations of Gregory et al.1 and Yang2. Similarly, the new correlation for slug frequency was compared with the correlation of Hill and Wood.
Flow-Induced Stress Distribution in a Multi-Rate and Multi-Well Reservoir
Authors: Sharma Amit , Chen Her-Yuan , Teufel Lawrence W.
Published: December 2007

The purpose of this study is to provide a model to infer the flow-induced rock-stress responses from the fluid-pressure transients of a vertical well in a homogeneous, anisotropic reservoir. The model is developed within the framework of Biot's theory of poroelasticity. Solutions for fluid-pressure and rock-stress responses are presented for an infinite reservoir in a state of plane strain. A published field case is presented to show the practical applications.

P. 97
Reservoir Description Techniques Improves Completion Economics in Piceance Basin Mesaverde Project
Authors: Schubarth S.K. , Mullen M.J. , Seal C.A. , Woodall R.S.
Published: December 2007

The Mesaverde formation in the Piceance Basin of western Colorado is a series of tight gas sands contained in a complex geological environment. Pay selection and completion techniques have varied greatly during the development of this formation. Production response varies greatly from well to well, and decisions on where and how to optimize completion economics are difficult. Consistent treatment sizes and designs are usually used even though some treatments may be over- designed while others are under-designed. Knowing where to spend Completion dollars and where to save them can substantially impact the economics of a development project in this Basin.

This paper will present a reservoir description technique that uses standard openhole well logs and helps operators to predict reservoir quality for individual sands. This prediction allows the operator to optimize the completion design and therefore maximize his economics. This technique has been applied to many wells, and the accuracy is documented through production analysis. Both total well production and individual sand production, determined with production logs, have been predicted through the use of this technique. This paper also examines the economic benefit of using this analysis technique will be presented. The authors believe that the methodology used can be applied to similar reservoirs to achieve similar results.

P. 129