bluuebunny/crossref_metadata_2025 huggingface dataset:
Interval Pressure Transient Testing With MDT Packer-Probe Module in Horizontal Wells
Authors: Kuchuk Fikri J.
Published: December 2007

In this paper, the use of various pressure measurements is investigated for determining formation pressure and permeability distributions by use of the multiprobe formation testing packer and probe modules (PPM's) in horizontal wells. It is shown that reservoir pressure measurements along the wellbore give local and reservoir-scale information about how the reservoir is being depleted and how cleanup takes place. The estimation of horizontal and vertical permeabilities, skin, and reservoir pressure along the wellbore is also presented by use of interval (local) pressure transient tests. For PPM in horizontal wells, an interpretation method is presented for determining the reservoir parameters. A few interval pressure transient test (IPTT) examples are presented for formation pressure and permeability distributions, and fluid sampling.
Teamwork Results in Wo rld-Record Length Casing String
Authors: Jellison M. J. , Eckroth J. J. , Fulton Jim , Ogren L. A. , Moore P. W. , Barber Vance , Vesely Don
Published: December 2007

On 12 April 1996 Louisiana Land and Exploration Company successfully ran and cemented a 14,510 ft string of 16-in. 146.2 lbf/ft (0.907-in. wall) P-110 casing in their Big Horn 4-36 well located in Fremont County, Wyoming. The string had an air weight of over 2.1 million pounds and a hook load of over 1.8 million pounds. This world record feat was the result of a concerted, team effort involving Engineering, Purchasing, Suppliers, and Service Companies. The 16-in. casing string played a critical role in drilling the well that had a total depth of over 24,000 ft. The paper details the complementary roles and contributions of each group involved in this challenging project. The overall well design philosophy is discussed along with a review of the detailed 16-in. casing design structural load and von Mises triaxial stress analysis. The specialized casing material specifications and manufacturing procedures are presented and related to casing string performance requirements. The paper outlines the casing connector selection criteria and describes the premium connector used on the casing string to withstand the high axial forces and pressures encountered while running the casing and drilling the well. The equipment and procedures used to safely and efficiently run the casing string in a total of only 43 hr from rig up to tear down with 31 hr running time are also described. The 14,510 ft casing string was cemented back to the surface in a single stage. The paper addresses the importance of the mud properties prior to cementing as well as the design and execution of the cement job. Both were critical to successfully completing the job.
Effect of Heterogeneity on the Non-Darcy Flow Coefficient
Authors: Narayanaswamy Ganesh , Sharma Mukul M. , Pope G. A.
Published: December 2007

An analytical method for calculating an effective non-Darcy flow coefficient for a heterogeneous formation is presented. The method presented here can be used to calculate an effective non-Darcy flow coefficient for heterogeneous gridblocks in reservoir simulators. Based on this method, it is shown that the non-Darcy flow coefficient of a heterogeneous formation is larger than the non-Darcy flow coefficient of an equivalent homogenous formation. Non-Darcy flow coefficients calculated from gas well data show that non-Darcy flow coefficients obtained from well tests are significantly larger than those predicted from experimental correlations. Permeability heterogeneity is a very likely reason for the differences in non-Darcy flow coefficients often seen between laboratory and field data.
Advantages of a New Chemical Delivery System for Fractured and Gravel- Packed Wells
Authors: Webb P. J. C. , Nistad T. A. , Knapstad Borge , Ravenscroft P. D. , Collins I. R.
Published: December 2007

The deposition of scale, such as carbonates and sulphates, in production facilities represents a serious operational problem that can result in significant well productivity decline. Current scale control strategies can involve significant capital and operational expenditure.

Development work, involving laboratory testing and a field trial, has demonstrated the technical benefits of a revolutionary method of downhole scale inhibitor delivery that can prevent scale deposition for a significant proportion of a well's lifetime. The method involves the slow release of scale inhibitor from porous proppants.

Economic analysis indicates that significant benefits can be derived for a variety of field development and well completion types. The greatest economic benefits would be realized for subsea and minimum facility installations with high intervention costs, where squeeze delivery of inhibitor or mechanical workover are used for scale control. In addition, major economic benefits can be realized for horizontal wells with unfavorable pressure regimes, multilateral-type completions, multiple fractured wells, and many conventional completion types.

The new chemical delivery method offers cost reduction through reduced deferred oil, efficiency of chemical usage, and fewer workovers using coil tubing and intervention vessels. Economic analysis has indicated that for some conventional and advanced well types, fracturing a well and deploying proppant impregnated with scale inhibitor, is economically preferable to a conventional strategy of squeeze treatment in an unfractured well.

An additional economic benefit of proppant impregnated with scale inhibitor is increased well productivity. The benefit is derived from the combined effect of improved gel breaking, and scale inhibition during well cleanup. This has been demonstrated in laboratory testing and would appear to be confirmed by field observations.

A further benefit of applying scale inhibitor as chemically impregnated proppant is the immediate treatment of produced water when water breakthrough occurs. This feature avoids the formation damage that can occur before squeeze treatment mobilization. In addition, for some applications involving large fractures there is the potential for lifetime well treatment.

This paper describes the laboratory work, the field trial, and the economic benefits of the new product.
Combustion/Oxidation Behavior of Athabasca Oil Sands Bitumen
Authors: Moore R. G. , Laureshen C. J. , Ursenbach M. G. , Mehta S. A. , Belgrave J. D. M.
Published: December 2007

Oils that are potential candidates for in situ combustion recovery processes are often screened by means of their oxidation characteristics: in particular, the kinetics of the ignition process and the transition from low-temperature to high-temperature oxidation through what is known as the "negative temperature gradient region." These characteristics are readily studied in ramped-temperature oxidation tests, which involve the controlled heating of recombined, oil-saturated cores in a one-dimensional plug flow reactor under a flowing stream of air (or oxygen-containing gas). The purpose of these tests is to study the global oxidation behavior and reaction kinetics under controlled conditions, with the end purpose of providing realistic data for incorporation into a numerical simulator which can be used to predict field performance.

A ramped-temperature oxidation apparatus was used to conduct a detailed, two-year parametric study of the oxidation characteristics of Athabasca Oil Sands bitumen. The text matrix involved various levels of pressure, gas injection rate, oxygen content of the injected gas, and maximum ramp temperature. This paper details the principal findings for the 45-test study; especially the need to maintain high reaction temperatures (> 380° C) in order to mobilize and produce heavy oils under conditions of dry in situ combustion. Design considerations and operational guidelines for successful field projects arising from the results of this study are also discussed.
Modeling Multicomponent Diffusion and Convection in Porous Media
Authors: Ghorayeb Kassem , Firoozabadi Abbas
Published: December 2007

Numerical investigations of diffusion and convection in multicomponent hydrocarbon mixtures in two-dimensional (2D) crosssectional (x,z) porous media are performed using the finite-volume method. Spatial discretization is performed by a second-order centered scheme. It is shown that methane, unlike in binary hydrocarbons where it often segregates towards the bottom-hot side of the porous media, may be at higher concentration at the cold-top side in ternary mixtures and in multicomponent reservoir fluids. This behavior, which is consistent with oilfield data, is due to competing diffusion mechanisms which have not been properly accounted for in the past. It is also demonstrated that convection may significantly affect the compositional variation in some hydrocarbon reservoirs. Depending on fluid mixtures, a weak convection may drastically change compositional variation.
Investigation of Fluid Conductive Faults and Modeling of Complex Water Influx in the Khafji Oil Field, Arabian Gulf
Authors: Nishikiori N. , Hayashida Y.
Published: December 2007

This paper describes the multidisciplinary approach taken to investigate and model complex water influx into a water-driven sandstone reservoir, taking into account vertical water flux from the lower sand as a suspected supplemental source.

The Khafji oil field is located offshore in the Arabian Gulf. Two Middle Cretaceous sandstone reservoirs are investigated to understand water movement during production. Both reservoirs are supported by a huge aquifer and had the same original oil-water contact. The reservoirs are separated by a thick and continuous shale so that the upper sand is categorized as edgewater drive and the lower sand as bottomwater drive. Water production was observed at the central upstructure wells of the upper sand much earlier than expected. This makes the modeling of water influx complicated because it is difficult to explain this phenomenon only by edgewater influx.

In this study, a technical study was performed to investigate water influx into the upper sand. A comprehensive review of pressure and production history indicated anomalous higher-pressure areas in the upper sand. Moreover, anomalous temperature profiles were observed in some wells in the same area. At the same time, watered zones were trailed through thermal-neutron decay time (TDT) where a thick water column was observed in the central area of the reservoir. In addition, a three-dimensional (3D) seismic survey has been conducted recently, revealing faults passing through the two reservoirs. Therefore, as a result of data review and subsequent investigation, conductive faults from the lower sand were suspected as supplemental fluid conduits. A pressure transient test was then designed and implemented, which suggested possible leakage from the nearby fault. Interference of the two reservoirs and an estimate of supplemental volume of water influx was made by material balance.

Finally, an improved full-scale numerical reservoir model was constructed to model complex water movement, which includes suspected supplemental water from the lower sand. Employment of two kinds of water influx—one a conventional edge water and another a supplemental water invasion from the aquifer of the lower sand through conductive faults—achieved a water breakthrough match.
Low-Field NMR Method for Bitumen Sands Characterization: A New Approach
Authors: Mirotchnik K. D. , Allsopp K. , Kantzas A. , Curwen D. , Badry R.
Published: December 2007

The nuclear magnetic résonance (NMR) signal obtained from conventional oil, heavy oil, and bitumen formations can consist of both hydrocarbon and water signals. Each NMR signal can further characterize both mobile and immobile fluids in the porous media. However, as the viscosity of the hydrocarbon phase increases and the NMR signal shifts toward lower relaxation times, the composite NMR signal for the hydrocarbon-bearing formation becomes very complicated. As the viscosity of the bitumen exceeds 100,000 cp (at natural conditions), the relaxation characteristics of bitumen become partially nondetectable by both the logging and laboratory NMR tools. As a result, the conventional methods of NMR detection fail to precisely recognize the hydrocarbon components.

Laboratory NMR measurements of bitumen-bearing porous media under different temperatures were performed. This method delivered new information about bitumen reserves in situ. The results show that low-field NMR holds promise for the characterization of recoverable heavy oil and bitumen reserves. This new approach can be applicable for real-time monitoring of thermal extraction, including monitoring the efficiency of thermal recovery methods.
Real-Time Monitoring and Control of Water Influx to a Horizontal Well Using Advanced Completion Equipped With Permanent Sensors
Authors: Bryant I. D. , Chen M. -Y. , Raghuraman B. , Schroeder R. , Supp M. , Navarro J. , Raw I. , Smith J. , Scaggs M.
Published: December 2007

We have tested new technologies for real-time monitoring and control of water influx to horizontal wells with sand-control completions. In a thin oil column in Indiana, we drilled a horizontal well and completed it openhole with sand screens and a gravel pack. External casing packers (ECPs) subdivided the annulus into three zones. An electrical valve, which also records the annular and tubing pressure, controls inflow to each zone. Twenty-one centralizers acted as electrodes to form a resistivity array that spans the 694-ft-long completion. The well was also equipped with a fiber-optic distributed-temperature-sensing (FODTS) system. The well has been produced since November 2001 and provides real-time data that are shared across a geographically distributed network and used to optimize the production of oil from the well.

The data from the pressure sensors and the resistivity array have been jointly interpreted to dynamically update the static reservoir model, which was initially based on observations in offset vertical wells. The pressures recorded from the three electrical valves provide high-frequency data to characterize the near-well heterogeneity of the formation. These data are critical to computing an optimum production strategy. Zonal well tests, combined with interference testing between zones and wells, enable the estimation of communication between zones and the productivity index (PI) of each zone. The resistivity data enabled detection of water-saturation changes both in the formation and in the wellbore.

The completion technology tested in this well offers the potential to intelligently operate horizontal sand-control completions by combining real-time monitoring with downhole inflow control.
Effect of Nonuniform Loading on Conventional Casing Collapse Resistance
Authors: Pattillo P. D. , Last N. C. , Asbill W. T.
Published: December 2007

In various locations worldwide, casing designers are confronted with nonuniform cross-sectional loading caused by contact with a mobile formation. The formation movement may be the result of rock constitution (salt, swelling shale), or it may be tectonic in origin.

Typically, well design proceeds with the goal of combating the nonuniform load. If this load occurs slowly, adjustments to the tubular design may be minimal, as the cross-sectional ovalization can only occur at the same rate as the formation movement. Adopting such an approach, however, ignores the fact that ovalization of the cross section because of nonuniform loading may also lower its collapse resistance to more conventional loads such as pressure differential (e.g., external pore pressure minus internal fluid pressure).

This paper documents the results of numerical and experimental studies to determine the effect of nonuniform loading on the conventional collapse resistance of casing. The current work focuses on casing exposed to external fluid pressure and extreme point loading, as might be the case in a poorly cemented wellbore.

An introductory section sets forth the problem with a specific design scenario for a production casing string loaded simultaneously by imposed ovalization caused by tectonic formation movement and collapse differential from the local fluid environment. The load is then simplified and solved numerically. The numerical results are first justified by physical argument, and then validated by full-scale collapse testing. Finally, the distinction between manufactured and imposed ovality is reinforced by comparison of the results with conventional collapse equations.
Factors Affecting Scale Inhibitor Retention in Carbonate-Rich Formation During Squeeze Treatment
Authors: Kan Amy T. , Fu Gongmin , Tomson Mason B. , Al-Thubaiti Musaed , Xiao Alan J.
Published: December 2007

Significant progress has been made toward developing a quantitative understanding of the inhibitor/rock interaction. In this study, four common oil field inhibitors (three phosphonates and one polyacrylate) are compared using carbonate-rich formation material. In addition to calcite (CaCO3) in the reservoir rock, several calcium inhibitor (Inh) solid phases are also important. Two reactions are central to the inhibitor retention in carbonate-rich formation: first, reduction of calcite dissolution because of surface poisoning by the Ca-Inh coating; and second, precipitation of Ca-Inh solid with either low Ca or high Ca stoichiometry. For NTMP, an acidic Ca-NTMP salt is formed at a low-pH environment. In addition, two crystalline Ca-NTMP phases and an amorphous Ca-NTMP salt may form, depending on the aquatic environment. Quantitative relationships between types of inhibitors, inhibitor acidity and concentration, and kinetics of calcite dissolution and calciumphosphonate precipitation are developed. Consequences of the observations on squeeze design and scale inhibition will be discussed.
Mechanism of Crude-Oil/Water Interface Destabilization by Silicone Demulsifiers
Authors: Dalmazzone C. , Noïk C. , Komunjer L.
Published: December 2007

Oil exploitation is always accompanied by the nondesired formation of emulsions caused by the presence of naturally occurring surface-active molecules such as asphaltenes and resins. Because their presence stabilizes the oil/water interface, it is necessary to break the emulsions by adding other surface-active molecules. Formulations based on polysiloxane molecules were selected as effective nontoxic products to enhance the oil/water phase separation. Establishing the relation between the efficiency of formulations and the interfacial properties of silicone molecules is the objective of this study. Formulation selection is based on bottle tests using turbidimetric measurements and on dynamic tests using a "dispersion rig" setup that allows the formation of emulsions under pressure and temperature conditions and injection of additives into the formed emulsion online. Rapid kinetics of separation and high levels of separated water were observed. Dynamic interfacial measurements were performed using complementary techniques. The drop-volume technique allows the measurement of the evolution of crude-oil/water interfacial tension with time. The Langmuir trough technique is used to obtain 2D compression isotherms and to deduce the elastic properties of interfaces. The coalescence of water droplets leading to the destabilization of emulsions and consequently to the oil/water separation efficiency can be related to the rheological properties of water/crude-oil interface. Therefore, such comprehensive study based on a specific methodology can lead to a strict and effective selection of emulsion breaker additives in relation with the oil composition.
The Application of High-Power Sound Waves for Wellbore Cleaning
Authors: Champion Brian , van der Bas Fred , Nitters Gerrit
Published: December 2007

This paper presents the results of a wide-ranging investigation into the application of high-power sound waves to remove plugging material from the wellbore and near-wellbore regions. This paper describes the process of generating high-power sound waves with a high-voltage electrical discharge and summarizes the results of the laboratory and test-well trials conducted on both simulated plugging materials and mudcake. The paper also references the development progress of a prototype wireline-conveyed, wellbore-cleaning system. The results of the investigation concluded that high-power sound waves represent a viable wellbore-cleaning technology with the potential to be applied effectively in removing various forms of wellbore-plugging material. Because this process can be applied selectively and in a controlled manner in the wellbore, without environmental impact and with standard wireline-deployment techniques, it offers considerable benefits vs. some existing solutions.
Perforating in Overbalance—Is It Really Sinful?
Authors: Chang F. F. , Kageson-Loe N. M. , Walton I. C. , Mathisen A. M. , Svanes G. S.
Published: December 2007

Drilling and completing long horizontal wells in North Sea oil fields is extremely costly. When perforating these long horizontal sections (>1000 m), deployment of the perforation guns on drill-pipe has been regarded as the safest and most cost-efficient method. The well is then kept in overbalance until the completion is installed.

To maintain well control, a fluid with loss-control capability [kill pill (KP)] is used as completion fluid during perforating to seal the formation immediately after perforating. This saves the time required to displace completion brine and the cost of losing the expensive brine into the formation. However, perforating with the kill fluid in the wellbore presents a great challenge in mini-mizing formation damage. Therefore, optimizing the perforating design and choosing the proper kill fluid are crucial tasks to ensure good well productivity. A thorough laboratory testing program has been performed to re-evaluate perforating strategy and completion-fluids selection for several fields in the North Sea. The fluid systems investigated include oil-based mud and water-based KPs formulated from formates and bromide brines.

The laboratory results have shown that if the perforating is designed and executed properly, formation damage can be reduced to a minimum even during overbalanced perforating. In this work, the major damage appears to be from the kill fluids. When using a water-based KP, the reduction in relative permeability appears to be an important damage mechanism. Therefore, the productivity is influenced strongly by the fluid-loss-control capability. In contrast, filtrate invasion from the oil-based mud does not alter relative permeability; therefore, the formation damage shown in these tests is less pronounced.

Furthermore, zinc- and steel-cased charges have been used to investigate their compatibility with kill fluids and their impact on formation damage. These studies have shown that interaction between zinc and CaBr2-based KPs can cause failure of fluid-loss control and excessive invasion of filtrate, leading to severe productivity impairment.

This paper presents some of the results of the laboratory testing program.
Influence of Drill-in Fluids Composition on Formation Damage
Authors: Sánchez Erna , Audibert-Hayet Annie , Rousseau Lionel
Published: December 2007

Drill-in fluids are generally water-based muds (WBMs) containing a viscosifier, a fluid-loss reducer, salts, and sized calcium carbonate particles. Formation damage mechanisms induced by the use of WBM formulations have been extensively studied and correspond to different phenomena such as water trapping, polymer adsorption and retention, and particle plugging. In this paper, a detailed study was carried out on the behavior of scleroglucan-based formulations generally proposed for high-temperature zones and/or high-permeability reservoirs and on the comparison with performances of xanthan-containing formulations. This work covers not only the effect of the fluid composition, including the presence or absence of drilled solids, but also the filtration conditions, such as shear rate and temperature. Mud filtrates have been characterized in terms of polymer content and by multiangle laser light scattering coupled with size-exclusion chromatography (SEC/MALLS) and filter cakes by cryo-SEM.

Filtration curves obtained under static conditions can be related to the rheological behavior and thermal stability of the biopolymer used as a viscosifier but not related to the solid content of the mud. Under dynamic conditions, the filtration curve strongly depends on the aggregation tendency of the scleroglucan sample.

Scleroglucan-based drill-in fluids present very good properties compared to classical water-based formulations at 120°C using a commercially available scleroglucan sample. The cryo-SEM dynamic filter-cake observations confirm a lower filter-cake permeability obtained under dynamic conditions with an homogeneous structure, no aggregates, and a structural polymer network.

When in contact with a borehole, for the same circulation time, a scleroglucan formulation will invade half the zone invaded by a xanthan-based formulation.
One Approach to the Grid Orientation Problem in Reservoir Simulation
Authors: Vinsome Paul K. , Au Anthony D. K.
Published: December 2007

Consider a linear, incompressible, two-phase flow in the absence of capillary pressure. Assume that a saturation shock front exists as depicted schematically in Fig. 1, and that the mobility behind the front is extremely high. During any time step of a numerical simulation, the exact position of the shock front generally is not known, so we assume that in an average sense the position of the shock may be placed midway between the nodes. In any numerical reservoir simulator that contains an upstream formulation, the value of Ss on Fig. 1 would be representative of the saturation at which the interblock phase mobility is evaluated. This would result in the calculation of the pressure profile shown by the solid Line P. There is clearly some inconsistency, as the true pressure profile is more like the dashed Line P′. Therefore, one possible source of the grid orientation effect is that the upstream finite-difference formulation produces far too small a pressure drop across a shock front, and that the directionally dependent pressure field truncation error is a significant fraction of this pressure drop.

Equating fluid velocities on either side of the shock front gives

where λT represents the total fluid mobility. If the pressure at the shock front ps is eliminated from these equations, we obtain

whereby it can be seen that the total effective mobility is given by

The harmonic mobility given by Eq. 3 is closer to twice the smaller value of (λTu, λTd) than to the upstream value, so it has the capability of producing larger pressure drops across a shock front.

On Fig. 1, it can be seen that the fluid fraction flowing at the shock front is more similar to the upstream value. This suggests that for the individual phase mobilities an upstream formulation should be used:
A New Iron-Based, Environmentally Friendly Hydrogen Sulfide Scavenger for Drilling Fluids
Authors: Davidson E. , Hall J. , Temple C.
Published: December 2007

A new scavenger has been developed that relies on the affinity between iron and sulfide. The active chemical is a form of ferrous iron complexed with a carbohydrate derivative. It is highly soluble in the brine phases of water-based mud (WBM) and will not precipitate at pH values greater than 12. When the iron is in solution, the reaction with sulfide is instantaneous and complete. This paper deals with the environmental implications of zinc vs. iron and the development of the new scavenger. It presents details of case histories concerning operations on a reservoir containing 25% hydrogen sulfide (H2S). Even in these demanding conditions, there was no H2S at surface.
Application of Lean Six Sigma in Oilfield Operations
Authors: Buell R. S. , Turnipseed S. P.
Published: December 2007

This paper summarizes the experiences and results that improve business performance using Lean Six Sigma in North American and Asian upstream oil and gas operations. The background and history on Lean, Six Sigma, and Intl. Standardization Organization (ISO) systems are also provided. The role ISO-quality systems can play in supporting Lean and Six Sigma is explained and demonstrated with examples. The overviews of completed Lean Six Sigma projects are provided for well testing, rod-pump repair, water treatment, oil treatment, well stimulation, and production logging.
Modeling of Severe Slug and Slug Control With OLGA
Authors: Fard Mehrdad P. , Godhavn John-Morten , Sagatun Svein I.
Published: December 2007

With the recent developments in the oil and gas industry, in which the number of satellite fields are increasing, the industry faces major challenges. A mixture of gas and oil is transported in multiphase pipelines along the bottom of the sea from the wells and up through the riser to the oil rig. The development of unstable flow in multiphase pipelines is a major and expensive problem. The irregular flow results in poor oil/water separation, limits the production capacity, and causes flaring. Handling slug flow thus has become very important with regard to increasing the production rate and avoiding possible equipment damages.

In this paper, we have developed a model of a physical process that generates slugs. The model has been verified against experimental data. Several control strategies have been tested on the model, and the simulation results are presented. It is shown by simulation of multiphase flow that the unstable slug flow can be stabilized by feedback control. In addition, interesting and important phenomena such as inverse response of the pressure at the top and asymmetric response of the pressure at the bottom have been revealed and explained.
Conditioning Truncated Gaussian Realizations to Static and Dynamic Data
Authors: Le Ravalec-Dupin Mickaële , Roggero Frédéric , Froidevaux Roland
Published: December 2007

The truncated Gaussian method is based on the transformation of continuous Gaussian realizations into discrete facies realizations. Each facies is associated to an interval that depends on its volume fraction. At a given location, the value of the continuous realization identifies an interval and, therefore, a facies. Within this context, the purpose of history matching is to produce facies realizations in agreement with the static facies observations and the measured dynamic data (pressures, water cuts, and flow rates). This problem is addressed through an optimization process: we minimize an objective function that measures the mismatch between the measured dynamic data and the corresponding simulated ones. During this iterative process, many truncated Gaussian realizations are investigated until we obtain the one that best reproduces the dynamic data. To account for the static data, all of the investigated truncated Gaussian realizations are constrained to the facies observations. This intermediate step is not as obvious as it seems. It requires the conversion of the facies observations to Gaussian values that respect both the spatial structure and the intervals characterizing the facies. Up to now, the algorithms that perform this conversion were very slow and were thus only used once during the optimization process. This constraint has a significant negative impact on the minimization of the objective function. We develop a new, and fast, conversion algorithm that turns facies observations into Gaussian values respecting the spatial structure and the intervals. In addition, it is well-suited for the gradual deformation algorithm. With the new proposed methodology, the converted Gaussian values can be gradually modified at the same time as the spatial distribution of the facies. This greatly speeds up the matching process. A numerical example is shown to compare the performance of the new matching approach with that of the conventional one.
Fracture Treatment Design and Execution in Low-Porosity Chalk Reservoirs
Authors: Cipolla C. L. , Hansen K. K. , Ginty W. R.
Published: December 2007

This paper details the results for 33 propped-fracture treatments in low-porosity zones in the South Arne (SA) field, Danish North Sea. To date, seven horizontal wells (2900 m total vertical depth [TVD]) have been completed using 100 tip screenout (TSO) propped-fracture treatments containing 70 million pounds of proppant. The target oil bearing Tor and Ekofisk intervals range from 40 to 120 m of combined thickness, with a Young's modulus and permeability that can vary from less than 0.5 to over 2.5 million psi and 0.1 to 4 m, respectively, along the horizontal section. The wide variations in reservoir and rock properties present significant fracture design and execution challenges.

Results indicate that propped-fracture treatments become increasingly more difficult to place as porosity decreases, and this problem is primarily attributed to higher natural fracture/fissure density in the lower-porosity, higher-modulus zones. Production data indicate that these natural fractures or fissures do not measurably contribute to productivity, but can be "activated" under fracturing conditions. Contrary to intuition, pad size and fluid-loss additives must be increased and maximum proppant concentration decreased in low-porosity (low-permeability) zones. In the higherporosity, higher-permeability northern portion of the field, pad sizes of 35,000 gal containing 20,000 lb of 100-mesh sand allowed the placement of 800,000 lb of proppant at concentrations up to 15 pounds of proppant added per gallon of fluid (ppa). However, in the lower-porosity, lower permeability southern portion of the field, pad sizes of 200,000 gal containing more than 100,000 lb of 100-mesh sand were required to place similar proppant volumes, with concentrations limited to 8 ppa. This paper summarizes field data from 100 treatments, illustrating the design changes necessary to place propped-fracture treatments in low-porosity chalk reservoirs. The paper documents the relationship between chalk porosity, fluid efficiency, and treatment design.
A New Effective Stimulation Treatment for Long Horizontal Wells Drilled in Carbonate Reservoirs
Authors: Nasr-El-Din Hisham A. , Al-Habib Nabil S. , Al-Mumen Adib A. , Jemmali Mohammed , Samuel Mathew
Published: December 2007

Effective matrix acidizing of horizontal and multilateral wells can be a highly challenging task. Unlike vertical wells, horizontal wells can extend several thousand feet into the formation. Reservoir heterogeneity and the length of the horizontal leg can make acid placement and diversion very difficult. In addition, the low drawdown encountered in horizontal wells results in longer times to lift the spent acid from the well, especially in tight formations.

To achieve better acid diversion in horizontal wells drilled in carbonate reservoirs, a viscoelastic-surfactant-based system was used. The components of this new system are HCl and a viscoelastic surfactant. The acid dissolves calcite and dolomite minerals and produces calcium and magnesium chlorides. The increase in pH forces the surfactant molecules to form rod-shaped micelles. The produced chloride salts further stabilize these structures, especially at high temperatures. The rod-shaped micelles will significantly increase the viscosity of the acid, diverting the acid into tight, unstimulated, or severely damaged zones.

More than 100 wells with openhole (OH) completions were successfully stimulated in two offshore oil fields in Saudi Arabia by use of the new acid system. With a water zone 30 ft away from these OH sections in one of the fields, growth of any dominant wormhole into these sections could increase water production. The wells that used the new treating fluid produced an average of 1,600 BOPD more than conventionally treated wells, with no indication of water production. Field results [pre- and post-oil and -water production rates and flowing wellhead pressure (FWHP)] demonstrate the effectiveness of the new acid system to matrix acidize long horizontal wells with OH completions. The simplicity of the system makes it the fluid of choice, especially in offshore and sour environments. The absence of metallic crosslinkers in this system eliminates problems associated with sulfide precipitation in sour wells.
Hot Oil and Gas Wells Can Be Stimulated Without Acids
Authors: Frenier Wayne , Brady Mark , Al-Harthy Salah , Arangath Roberto , Chan Keng Seng , Flamant Nicolas , Samuel Mathew
Published: December 2007

A revolutionary family of treating fluids designed for the stimulation of critical, hot, or exotic oil and gas wells has been developed through application of detailed chemical and engineering studies.1–3 Formulations based on the hydroxethylaminocarboxylic acid (HACA) family of chelating agents have now been used to successfully increase production of oil and gas from wells in a variety of different formations. Included in the field test matrixes were new and producing wells drilled into carbonates and sandstone formations. The temperatures of the wells treated ranged from 230 to 370°F (110 to 187°C) bottomhole static temperature (BHST).

Because these formulations do not contain high concentrations of corrosive mineral or organic acids (the formulations are less acidic than carbonated beverages), very low corrosion rates of the tubulars can be achieved by application of small amounts of special, inexpensive corrosion inhibitors. The mild fluids also are highly retarded so that high-temperature carbonates can be stimulated and sensitive sandstone formations are not damaged. The fluids have reduced health, safety, and environmental (HSE) footprints because:

They are much less toxic to mammals as well as to aquatic organisms than mineral acids or organic acids such as hydrochloric (HCl), hydrofluoric (HF), or formic acid. The fluids are returned to the surface at pH values between 5 and 7, and they frequently can be added to normal well production fluids without neutralization. Because of much lower corrosion rates for corrosion resistant alloys (CRAs), lowered concentrations of Ni and Cr will be in the well returns compared with conventional acids that also may contain antimony (as a corrosion inhibitor).
Stabilized Productivity of a Hydraulically Fractured Well Producing at Constant Pressure
Authors: Hagoort Jacques
Published: December 2007

This paper describes a simple and easy-to-construct numerical model for the calculation of the stabilized productivity of a hydraulically fractured well producing at a constant well pressure. The model takes into account both Darcy and non-Darcy pressure losses in the fracture. Dimensionless charts are presented that illustrate productivity improvement as a function of fracture length, fracture conductivity, and non-Darcy flow. For dimensionless fracture lengths in excess of 0.2, constant-pressure productivities are significantly lower than constant-rate productivities as predicted, for example, by the McGuire-Sikora productivity improvement chart. The maximum difference is 20% for an infinite-conductivity fracture with a length of unity. Both fracture conductivity and non-Darcy flow adversely affect well productivity; the reduction in productiv-ity is larger for longer fractures.
Effect of Water Cut on Sand Production—An Experimental Study
Authors: Wu Bailin , Tan Chee P. , Lu Ning
Published: December 2007

It is commonly acknowledged in the petroleum industry that water cut increases sand-production risk, and a number of possible mechanisms have been proposed. This paper presents the results of a series of laboratory perforation-collapse tests aimed at demonstrating and quantifying the water-cut effect on perforation failure and sand production.

The laboratory perforation-collapse tests were conducted on weak sandstones obtained from downhole and outcrop. The tests were performed under simulated in-situ effective stresses and drawdown conditions. Water was introduced into the flowing stream of either oil or gas at various stages of the tests to simulate water cut. The failure and sand-production processes were observed and recorded using a borescope in real time.

The results showed that the effect of water cut on perforation strength and sand production depends on the mineralogical composition of the sandstone and the degree of residual water saturation. The effect is most significant for sandstones with high clay content and low residual water saturation and is less significant for clean sandtones or those with high residual water saturation. The experimental results are discussed on the basis of the chemical interaction between water and rocks—capillary stress and relative permeability. It is concluded that water-saturation-induced rock-strength reduction is the most significant factor governing perforation failure and sand production. Although perforation failure is a prerequisite for sand production, the failure does not always lead to sand production.
A Simple Model for Annular Two-Phase Flow in Wellbores
Authors: Hasan A. R. , Kabir C. S.
Published: December 2007

Annular flow is associated with production from both gas-condensate and geothermal wells. Oil wells also experience it during high-gas-to-oil-ratio (high-GOR) production. The current semimechanistic modeling approach requires estimation of film thickness before computing frictional pressure drop as gas flows past the wavy-liquid film surrounding the pipe wall. This study intends to investigate this film thickness and its impact on pressure-drop computation in wellbores producing steam-water, gas-condensate, and gas-oil mixtures.

Computational results show that this dimensionless liquid-film thickness is most likely less than 0.06 in annular flow. For such values of thin-film thickness, the computed friction factor is only slightly higher than that estimated with a smooth-channel assumption. When the homogeneous model is used to compute pressure gradient by ignoring the wavy-liquid film on frictional pressure drop, good agreement is achieved with field data and with the predictions of a semimechanistic model.
A Laboratory Study With Field Data of Downhole Gas Separators
Authors: McCoy J. N. , Podio A. L. , Lisigurski Omar , Patterson John , Rowlan Lynn
Published: December 2007

Downhole gas separators are often the most inefficient part of a sucker-rod pump system. This paper presents laboratory data on the performance of five different gas-separator designs. Only continuous flow was studied. Field data are presented on two of the designs. The field data indicate that success or failure of the gas separator is dependent upon the fluids and wellbore pressures as well as the mechanical design of the gas separator. Successful and unsuccessful examples of gas-separator performance in the field are shown along with field fluid data properties.
Application of Gas Lift Technology to a High-Water-Cut Heavy-Oil Reservoir in Intercampo Oilfield, Venezuela
Authors: Hong'en Dou , Yuwen Chang , Dandan Hu , Wenxin Cai , Guozhen Zhao
Published: December 2007

This paper presents successful applications of gas lift technology to heavy-oil reservoirs in Intercampo oilfield, Lake Maracaibo, Venezuela. Liquid production rates range from 10 to 320 m3/day per well. Gas lift was selected as the first artificial lift method in the oilfield. The paper describes the gas lift mechanisms applied in a high-water-cut heavy-oil (below 15 API) reservoir. The theoretical analysis showed that the injection gas rate for gas lift and the gas/oil ratio (GOR) of an oil well have direct effects on the fluid flow from the wellbore.

Theoretical design and actual gas lift production are described in the paper. The correlations used for artificial gas lift design for high-water-cut heavy oil need to be refined to match the field data. The difference between theoretical design and actual production is significant for high-water-cut heavy oil lower than 15 API. Formation of oil/water emulsion was not observed during gas lifting of low-API, high-water-cut oil from wells.

In this study, a correction coefficient for gas lift design was applied to a high-water-cut, low-API field. Further work is needed to refine this gas lift design software. It should prove particularly useful for production engineers in optimizing the design of gas lifting equipment.
Controlling Formation Fines at Their Sources To Maintain Well Productivity
Authors: Nguyen P. D. , Weaver J. D. , Rickman R. D. , Dusterhoft R. G. , Parker M. A.
Published: December 2007

Migration of formation fines has been shown to cause production decline in many wells. Despite the availability of new downhole tools for use in well stimulation and completion, the ability to sustain desired production levels is often plagued with fines migration problems. The solution to this problem is appropriate treatment to mitigate fines migration at its source. This paper describes the use of an ultra-thin tackifying agent (UTTA) for stabilizing fines in high-rate producing or injection wells. This UTTA is applied as part of an initial prepad in fracturing or gravel-packing operations, as a remedial treatment, or as a post-treatment following acid fracturing or matrix acidizing treatments. The primary purpose of UTTA application is to immobilize formation fines so that they will not detach, migrate with flowing fluids, plug the pore channels, and reduce the flow path permeability.

Results of laboratory testing indicate that the UTTA system is applicable to most types of formation fines, including coals, sandstones, and carbonates. Once injected into the formation matrix or proppant pack, the UTTA forms a thin film on formation surfaces, encapsulating the fines. Capillary action helps pull the tackifier into the contact points, fixing the particulate in place without plugging the pore throat. The UTTA does not require a shut-in time after its application. The thin film tackifier does not harden, but remains flexible, enhancing the ability of a formation to withstand stress cycling and allowing the formation to handle high shear stress during high flow rates.
Gas Storage and Operations in Single-Bedded Salt Caverns: Stability Analyses
Authors: Han Gang , Bruno Mike , Lao Khang , Young Jean , Dorfmann Luis
Published: December 2007

Bedded salt formations are located throughout the U.S., providing valuable storage capacity for natural gas and other hydrocarbons. To increase gas-storage capabilities and provide operators with improved geotechnical design and operating guidelines for these caverns, stability analyses of single-bedded salt caverns have been completed and are described in this paper. This work is a part of integrated efforts initiated and sponsored by the U.S. Department of Energy (DOE), the Gas Technology Institute (GTI), and Pipeline Research Council International, Inc.

Numerical geomechanical models have been developed to investigate single-cavern deformation and bedding-plane slip for a variety of cavern configurations. A viscoplastic salt model has been developed based on an empirical creep law developed for the Waste Isolation Pilot Plant (WIPP) Program and combined with a Drucker-Prager model for damage and failure. The nonsalt materials are described with either a traditional Mohr-Coulomb model, or an elastic model, depending on layer properties.

A baseline model with specified geometric dimensions is first selected and subjected to 1-year cyclic pressure operations. The amount of damage around the cavern wall and roof is evaluated and used as a comparison in the study. Then, the operations are extended to 15 years to study cavern stability for long-term gas storage and operations. In addition to the baseline model, parametric studies have been performed to investigate cavern damage as a function of salt roof thickness, overburden stiffness, interface properties, and cavern geometries. Each cavern simulation includes 1 year of pressure cycling with a minimum, mean, and maximum cavern pressure of 6.1 MPa (884.5 psi), 8.8 MPa (1,276 psi) and 14.9 MPa (2,160.5 psi), respectively. Different operation conditions (e.g., hydrostatic, cyclic, and direct-pressure drawdown) are compared and evaluated in terms of cavern stability.

These analyses can be a basis to selecting the best salt cavern candidate for gas storage and operations as well as helping to assess critical cavern design parameters for thin-bedded salt formations.