bluuebunny/crossref_metadata_2025 huggingface dataset:
A New Unfree Fluid Index in Sandstones Through NMR Studies
Authors: Borgia G. C.
Published: December 2007

Nuclear magnetic resonance (NMR) of 1H nuclei of liquids in saturated porous rocks furnishes an increasingly important tool in core analysis as well as in well-logging. In particular, there are several basic questions regarding NMR downhole logging in reservoir sandstones. For this reason, it is of interest to investigate the laboratory NMR properties to identify some important basic mechanisms. This paper presents new correlations among porosity, ϕ, irreducible water saturation, Swi, formation resistivity factor, F, and the geometric mean longitudinal relaxation time, T1g. Equilibrium magnetization and longitudinal relaxation, T1, measurements were performed on 57 clean sandstone samples from 12 oil and gas reservoirs. NMR measurements ϕNMR of ϕ agreed very well with conventional porosity measurements. The product of porosity and irreducible water saturation is approximately equal to an unfree fluid index, UFFI=(ϕNMR/T1g)2/3, giving an error-of-estimate factor of 1.24. The best estimate of Swi based on a simple cut-off relaxation time (35 ms) gave an error factor of 1.6. The present correlation of Swi with ϕNMR and Tig is nearly as good as the correlation using T1g and F, and it has the advantage of requiring only NMR measurements on fully saturated samples. No further improvement in correlation with Swi was obtained by using T1g with both ϕ and F over that with T1g and F only. The correlation with F was slightly better than that with ϕ. The effectiveness of using both T1 and either F or ϕNMR is plausible, since T1, being sensitive to surface-to-volume ratio, gives some information on pore or pore channel dimensions, while ϕNMR, being correlated with F, gives some information on connectivity within a sandstone. Large pores connected only by very small channels contribute to long T1 but contribute also to Swi. The above use of ϕNMR and T1 should be useful for laboratory measurements on cores; furthermore, since T2 is closely related to T1 at the low measurement frequencies used in nuclear magnetism logging, it is very likely that a similar relationship (probably with different parameters) may relate Swi to ϕNMR and T2 obtained in downhole measurements.
Characterization of a Complex Fluvial-Deltaic Reservoir for Simulation
Authors: Begg S. H. , Kay Alex , Gustason E. R. , Angert P. F.
Published: December 2007

Lithotype is shown to be the main geological control on the spatial distribution of reservoir flow properties. The distribution of lithotypes is in turn controlled by lithofacies. Using core data, assemblages of lithotypes were grouped into major facies associations (MFA's). Log signatures were used to pick MFA's in uncored wells to provide conditioning data for a stochastic description of their interwell distribution using the sequential indicator simulation (SIS) technique. Deterministic correlation was not enforced.

Characteristic object-models of the distribution of lithotypes within each MFA were then generated and converted to fine-scale poro-perm models using core-plug data. These models were ups-caled to yield characteristic poro-perm distributions at the reservoir simulation scale. Finally, the MFA model was used as a template to distribute the upscaled poro-perm within the simulation model. The model history-matched rapidly and accurately, even though the wells were conditioned only to the MFA's and not to foot-by-foot data. Multiple MFA realizations were generated to provide some understanding of the uncertainty in thickness and other rock properties between wells.
A Wellbore/Reservoir Simulator for Testing Gas Wells in High-Temperature Reservoirs
Authors: Kabir C. S. , Hasan A. R. , Jordan D. L. , Wang Xiaowei
Published: December 2007

Gas wells frequently exhibit changing storage during a transient test because of high fluid compressibility. Further complications may arise owing to heat exchange between the wellbore fluid and the formation, especially in high-temperature reservoirs. Thus, fluid temperature changes during a transient test, thereby complicating test interpretation when surface measurements must be used in a hostile downhole environment.

This paper describes the application of a wellbore/reservoir simulator. This simulator can be run in two modes. In forward modeling, the wellhead pressure, temperature, and bottomhole pressure can be computed as a function of time, given reservoir parameters and well-completion details. In contrast, reverse simulation directly translates measured wellhead pressure (WHP) and temperature (WHT) to bottomhole pressure (BHP) for subsequent analysis.

Forward simulation of wellbore pressure and temperature is a valuable tool for designing transient well tests. In particular, in a hostile downhole environment, the ability to estimate BHP accurately from wellhead measurements is an invaluable asset where downhole measurements may not be cost effective. Even in favorable situations, the simulator can aid both test design and interpretation.

Application of the simulator to field examples has helped us gain considerable insight into the mechanics of transient flow in the wellbore. For example, we observe a denser fluid toward the wellhead rather than at the bottom of the well because of the temperature effect. Consequently, decreasing storage behavior is observed at the bottom of the well.

Two field examples obtained from a Gulf Coast gas field are used to illustrate the capabilities of the simulators. Good agreement is noted between the computed and measured BHP's during both types of simulations.
The Role of Geology in the Behavior and Choice of Permeability Predictors
Authors: Ball L. D. , Corbett P. W. M. , Jensen J. L. , Lewis J. J. M.
Published: December 2007

For effective flow-simulation models, it may be important to estimate permeability accurately over several scales of geological heterogeneity. Critical to the data analysis and permeability prediction are the volume of investigation and sampling interval of each petrophysical tool and how each relates to these geological scales. We examine these issues in the context of the As Sarah Field, Sirte Basin, Libya.

A geological study of this braided fluvial reservoir has revealed heterogeneity at a series of scales. This geological hierarchy in turn possessed a corresponding hierarchy of permeability variation. The link between the geology and permeability was found to be very important in understanding well logs and core data and subsequent permeability upscaling.

We found that the small scale (cm) permeability variability was better predicted using a flushed-zone resistivity, Rxo, tool, rather than a wireline porosity measurement. The perm-resistivity correlation was strongest when the probe permeabilities were averaged to best match the "window size" of the wireline Rxo. This behavior was explained by the geological variation present at this scale. For the larger scale geological heterogeneity, the production flowmeter highlighted discrepancies between flow data and averaged permeability. This yielded a layered sedimentological model interpretation and a change in averaging for permeability prediction at the bedset scale (ms-10 × ms).
Effects of Viscous Fingering on Fracture Conductivity
Authors: Pope D. S. , Leung L. K. , Gulbis J. , Constien V. G.
Published: December 2007

Understanding the causes of damage to fracture conductivity is vital in design of fracture treatments for maximum economic value and to analyze the actual well performance. High-viscosity fluids, resulting from retention of polymer within the proppant pack during closure, play a major role in proppant-pack damage. Viscous fluids are not effectively displaced during flowback and production of hydrocarbon unless the viscosities of the phases are similar. The consequences of viscous fingering in the fracture are discussed, and a method is presented for predicting the retained permeability of proppant packs in which guar-based hydraulic fracturing fluids have been broken. Data required for the method are temperature, polymer molecular weight, and final polymer concentration.
An Experimental Study on Downward Slug Flow in Inclined Pipes
Authors: Roumazeilles P. M. , Yang Jiede , Sarica Cem , Chen X. T. , Wilson J. F. , Brill J. P.
Published: December 2007

The downward simultaneous flow of gas and liquid is often encountered in hilly terrain pipelines and injection wells. Most of the methods for predicting pressure drop in gas/liquid, two-phase flow in pipes have been developed for either upward vertical or upward inclined pipes. This study experimentally investigates downward co-current slug flow in inclined pipes. A new test facility was designed and built to acquire data for the entire range of pipe inclination angles. A series of slug flow experiments was conducted in a 2-in. diameter, 65-ft long clear PVC pipe installed on an inclinable structure. Liquid holdup and pressure drop measurements were obtained for downward inclination angles from 0° to −30° at different flow conditions. Translational velocity and liquid-slug holdup correlations were investigated based on the acquired data for different inclination angles.
Real-Time Monitoring of Matrix Acidizing Including the Effects of Diverting Agents
Authors: Hill A. D. , Zhu Ding
Published: December 2007

Real-time monitoring of the injection rate and pressure during matrix acidizing provides operators with a way to determine the changing skin factor as stimulation proceeds. Current methods are based either on the assumption of steady-state flow in the region around the wellbore affected by acid injection or on computer solution of the transient flow equations describing the unsteady reservoir flow process occurring during acidizing. In this paper, a new method for real-time monitoring of matrix acidizing, the inverse injectivity vs. superposition time function plot, is presented. This new method can be applied with a spreadsheet computer program or a programmable calculator and accounts for the transient flow effects occurring during matrix acidizing at multiple rates and injection pressures. The evolving skin factor during a matrix treatment is readily obtained from the diagnostic plot. Hypothetical examples show how the inverse injectivity plot can be used to assess the efficiency of stimulation and diversion. Comparisons with previously presented field cases show the new method to be a simple and accurate means of monitoring the evolving skin factor during matrix acidizing.
Fracture-Injection-Test Interpretation: Leakoff Coefficient vs. Permeability
Authors: Mayerhofer M. J. , Economides M. J.
Published: December 2007

Determining the leakoff coefficient from a minifracture pressure decline has become a relatively common industrial procedure. A main assumption of the method, which is often referred to as the Nolte analysis, is a constant leakoff coefficient. Frequently there is no constant leakoff coefficient. The definition of the coefficient is based on a constant pressure differential and a prescribed mode of leakoff. In contrast, the analysis for fracture-pressure decline, introduced by Mayerhofer et al.,10 couples unsteady-state linear flow from the fracture with a varying skin effect at the fracture face, and superposes the leakoff history on the pressure decline. This guarantees a correct rate convolution to account for pressure-dependent fluid loss. The reservoir permeability, fracture-face resistance, and leakoff area can be determined. A comparison of the two methods and their relationship is presented in this paper, using real field cases. We show that the use of modern well-testing log-log diagnostic plots to determine fracture closure pressure is superior to drawing a straight line on a G-function plot or a square-root-of-time plot.
Wettability and Spreading: Two Key Parameters in Oil Recovery With Three-Phase Gravity Drainage
Authors: Vizika Olga , Lombard J. -M.
Published: December 2007

The objective of this paper is to show that the porous medium wettability and the spreading characteristics of the fluid system hold the key roles in three-phase gas injection, and to study to which extent these two parameters affect oil recovery and phase distributions. To this end gravity assisted inert gas injection experiments have been performed in water-wet, oil-wet and fractionally-wet porous media for spreading and nonspreading conditions. The experiments are simulated and the oil and gas relative permeabilities for three-phase flow are calculated by history matching. It is proved that the existence of wettingandspreading oil films—caused by wettability and spreading—greatly affects the flow mechanisms and consequently the recovery kinetics and the process efficiency. The results are interpreted in terms of physicochemical parameters on the basis of pore scale mechanisms.
Offshore Application of a Novel Technology for Drilling Vertical Boreholes
Authors: Foster P. E. , Aitken A.
Published: December 2007

A new concept for automatically drilling vertical boreholes was recently implemented by Elf Enterprise Caledonia - the Vertical Drilling System. The VDS was used to drill the 16" hole section of a North Sea exploration well. This was the first time this technology had been used offshore, drilling from a semi-submersible drilling unit. The VDS was shown to have an application in penetrating a drilling target that required a near vertical wellbore. Technical functioning of the tool and field experience is reported along with performance comparisons to offset wells.
Lateral-Jet Hydraulics and Oval-Cutter Technology Combine To Improve PDC Performance, North Sea Scott Field
Authors: Lewis J. P. , Begbie R. J. , Simpson Neil
Published: December 2007

The successful implementation of lateral-jet polycrystalline diamond cutter (PDC) hydraulics has emerged over the last few years with quantifiable results. Lateral jets set into the blades of the bit improve the cutter cleaning efficiency, thereby increasing the rate of production (ROP). In addition to cleaning the plenum in front of the jet, fluid entrainment creates a Venturi effect, drawing the fluid across the blades serviced by the downward jets. This flow is then ejected at high speed to the junk slots.

The operators of the North Sea Scott field took a major initiative in this development, and in conjunction with the lateral-jet company, expanded the technology to initiate a new cutter design and the second generation of lateral-jet-type bits, the fully lateral-jet PDC drill bit.

This paper will track the development of the technology from the initial trials of lateral jets in the Scott field, the rationale and design criteria that initiated oval PDC cutters, and most recently the fully lateral-jet bit.
Causes and Solutions to Surface Facilities Upsets Following Acid Stimulation in the Gulf of Mexico
Authors: Durham D. K. , Ali S. A. , Stone P. J.
Published: December 2007

Severe upsets frequently occur in surface treating facilities following acid stimulation in the Gulf of Mexico. Such upsets usually occur after fluids from the stimulated well are commingled with fluids in the system. Often the emulsions formed are extremely difficult to treat, requiring either large amounts of chemicals or unusually long separation times. These problems, combined with the more stringent discharge limits on produced water in the Gulf of Mexico, make the control of acid flowbacks a vital consideration in maintaining an acceptable and consistent discharge water quality.

This paper presents test data on the effects of acid and acid additives on emulsion and water treating in the Gulf of Mexico. This work also discusses the test methods developed to select acid additives and treating chemicals that will allow the producer to treat both oil and water more consistently and cost effectively while the acid flowback is in the system. It also presents system results that confirm the importance of the joint selection of acid and surface treating additives and show that significant cost savings can be gained by use of this process.

Also discussed are the proper system application techniques for treating chemicals that can minimize surface treating problems caused by acid flowbacks. The results show that the proper selection and use of acid additives and surface treating products can eliminate or significantly reduce costly upsets in oil- and water-treating systems. Data on individual acid additives that impact water and oil treating are also presented. The results of this work are currently being used to solve produced-water- and oil-treating problems on offshore and onshore facilities in and around the Gulf of Mexico by reduction of production losses resulting from acid-flowback-related problems; reduction of the use and cost of tanks and barges used to segregate acid flowbacks; and development of effective methodology to select acid and surface treating additives that have resulted in lower overall treating costs.
Foam Diversion Modeling and Simulation
Authors: Robert J. A. , Mack M. G.
Published: December 2007

This paper presents a model of foam rheology in porous media, based on a set of experimental data gathered in linear cores at rates relevant to matrix-acidizing conditions. Foam was found to behave as two-phase flow, with a minimum yield stress required to displace the gas phase. At high foam rates, foam was highly shear-thinning, and the pressure gradient within the foam bank was observed to be independent of the foam rate. It was also found that nitrogen solubility in the aqueous phase can explain the long-term behavior of foam banks under brine flow.

The modeling is applied to foam-flow simulation. In a two-phase finite-difference simulator, foam flow is represented by modifying the relative permeability to gas at each timestep, as a function of the injection conditions. Surfactant transport and adsorption and gas solubility have also been integrated into the simulator.

Comparisons between simulation results and diversion experiments are presented, and the possibility of extension to field conditions is demonstrated by simulation of a hypothetical field case.

Finally, the effects of surfactant adsorption and foam-injection conditions on diversion efficiency are briefly discussed.
Effectiveness of Chemically Enhanced Solubilization of Hydrocarbons
Authors: Kan A. T. , Hunter M. A. , Fu Gongmin , Tomson M. B.
Published: December 2007

Hydrocarbon spills and leaks are a major source of groundwater pollution for urban and industrial regions of the United States. Cleanup is most often attempted using pump-and-treat methods with numerous wells and a central treatment facility. Such procedures are notoriously inefficient when hydrocarbons are trapped in oil ganglia or capillaries, or are irreversibly sorbed. The residual hydrocarbons cannot be displaced under reasonable hydraulic gradients. Therefore, it is important to develop a more efficient method of removing such a pollutant source. Miscible solvents and surfactants are often proposed as the chemical enhancer for pump and treat. Several researchers have applied the surfactant flush in both the laboratory soil columns and field-test plots. The efficiency of surfactants usually diminished within 20 pore volumes and a significant fraction of contaminant was not mobilized. Some thermodynamic or kinetic limitations may exist in surfactant flush. Research has shown that surfactant often adsorbed to soil and altered the adsorption/desorption properties of soil. These processes may be reversed by controlling the pH and ionic strength. Miscible solvent has been shown very effective in laboratory tests. There are strong reasons to believe that a combination of several enhancement regimes will have substantial performance advantages. Just as with bioremediation, different chemical-enhancement methods will probably be better suited to particular combinations of contaminant types and aquifer characteristics. This paper discusses the effectiveness of chemical-enhancement treatments and possible limitations.
Cost-Effective Design of Scale-Inhibitor Squeeze Treatments Using a Mathematical Model
Authors: Kokal S. L. , Raju K. U. , Bayona Hector
Published: December 2007

Scale formation and deposition in production facilities is a challenging problem faced by the oil industry. Their deposition leads to operational problems, safety hazards, and an overall decrease in production efficiency. Downhole scale-inhibitor squeeze treatments provide the most common and effective means of preventing the formation of oilfield scale deposits.

This paper presents an analysis and design study of field-inhibitor squeeze treatments. A mathematical model was used to simulate inhibitor-squeeze return data from several Saudi Aramco wells. A wide range of sensitivities in squeeze treatments were investigated, including inhibitor concentration, inhibitor volume, overflush size, and shut-in time. An optimization of the squeeze injection parameters was carried out with the numerical simulator. This optimization was based on squeeze performance as well as on economic criteria. The results indicate that the optimized treatment strategy is very well-specific and depends on the water production rates and operational parameters, like the scale-inhibitor concentration and volume and the amount of overflush. Recommendations are made for optimizing (in terms of cost effectiveness) the squeeze-treatment design.
Development and Application of a Wellbore/Reservoir Simulator for Testing Oil Wells
Authors: Hasan A. R. , Kabir C. S. , Wang Xiaowei
Published: December 2007

A comprehensive coupled wellbore/reservoir simulator was developed to study the behavior of single-phase oil flow in the wellbore. The wellbore is modeled numerically where mass, momentum, and energy of the fluid are conserved, while the reservoir fluid flow is treated analytically. Energy transport occurs through tubulars, cement sheaths, and the formation by conduction. However, both conductive and convective heat-transport mechanisms are operative for the annular fluid. Heat losses through seawater and air are also modeled for a well producing in an offshore environment.

A sensitivity study shows that heat loss through seawater becomes significant for long submerged tubulars (> 2,000 ft), but is marginal for shorter pipes because of the fluid's short residence time. Further, a deviated well loses more heat to formation than its vertical counterpart for the same reason. Of the major variables, thermal conductivity of the annular fluid plays a key role in heat retention and, therefore, the wellhead temperature (WHT). We have identified the phenomenon of thermal storage. This storage behavior is associated with heat absorption or desorption by cement sheaths and tubulars and is reflected as the time taken to attain equilibrium WHT for a given flow rate. A longer storage period occurs at low flow rates because of lower associated fluid enthalpy.

Field data were used to demonstrate various applications of the simulator. We showed that both drawdown and buildup data of bottomhole pressure (BHP), wellhead pressure (WHP), and WHT can be modeled successfully given the tubular, completion, and reservoir data. Conversely, given the wellhead measurements (WHP and WHT), BHP values comparable to those measured can be computed.
Seismic Data Can Improve Stochastic Facies Modeling
Authors: Tjølsen C. B. , Johnsen Gyrid , Halvorsen Gunnar , Ryseth Alf , Damsleth Eivind
Published: December 2007

Heterogeneous reservoir units comprised of fluvial channel sandstones that alternate vertically and laterally with finer grained, nonreservoir lithologies pose a serious problem to production drilling and field development planning. The interwell position of each reservoir sandstone body can be assessed, in most cases, only indirectly through conventional geological well-correlation and mapping, and the potential of drilling unsuccessful production wells is usually present.

The scope of this paper is to present a new technique that ensures that information obtained from 3D seismic surveys is fully utilized in the discrete facies modeling of fluvial sandstone bodies in a heterogeneous reservoir unit.

In our study area, we show that there is a useful, empirical relationship between seismic impedance and the facies (channel sandstones/nonreservoir). Notably, there is a high probability of obtaining channels in low impedance regions, whereas high impedance areas have a lower probability of channels. An opposite impedance behavior may occur in other reservoir environments.

This relationship is utilized to guide the discrete modeling of channels. An example from a fluvial North Sea reservoir is presented. The use of seismic data as an additional source of conditioning data reduces the uncertainty in the stochastic reservoir model, because the uncertainty in the reservoir description in the interwell areas is reduced significantly.
Stressed Oil Permeability of Deepwater Gulf of Mexico Turbidite Sands: Measurements and Theory
Authors: Ostermeier R. M.
Published: December 2007

Repeatable and reliable brine permeability measurements on sand and sandstone samples often have been suspect because of the possible occurrence of fines movement and migration. This is especially true for unconsolidated sands. To avoid the effects of fines movement and to isolate the effects of stress and compaction, oil permeability measurements were made by flowing refined oil through turbidite sand samples prepared at initial water saturation, Swi. In this state, any fines present are presumably water-wet and are thus immobilized in the water phase.

The methodology for doing these measurements is briefly reviewed, and data from several deepwater Gulf of Mexico (GOM) turbidite sands is presented. By eliminating fines migration as an issue, compaction effects on permeability are shown to be quite significant for these sands.

Based on simple scaling arguments as applied to tubular laminar flow, a permeability model has been developed and found to be in good agreement with the experimental data. This model provides a reliable means of estimating permeability given porosity, initial water saturation, and grain-size distribution. The model is not turbidite specific; it may be applicable to other sand depositional environments.
Deepwater Pipeline Intervention Work With an Acoustically Controlled Power Module
Authors: Confer Aurelio , Launaro Fabio , Bigoni Guiseppe
Published: December 2007

The stabilization of submarine pipeline free spans along uneven sea bottoms is performed conventionally using technologies such as gravel dumping, post trenching, and mattress installation. A new technology has been developed to support free spans along the 26-in. Transmed Gas Pipelines crossing the Sicily Channel in water depths ranging from 50 m to 510 m. This technology is based on the pipeline mechanical support "Atlantis" and its installation module "Pegaso" and was developed keeping requirements such as short installation time, system redundancy, operational flexibility, and simple interface with the support vessel in mind.

The installation time reduction is achieved by automatic operational procedures that are controlled acoustically from the surface. Power is stored inside two dedicated battery packs placed on board Pegaso; no umbilical cable is necessary, so that a vessel equipped with a normal crane is enough to launch and operate the system.

Marine operations carried out in 1993 showed that a support can be installed in about 1 hour. In good weather conditions, three Atlantis were installed in 24 hours, including deck operations for recharging the battery packs. A total of 16 supports was installed along the 4th and 5th Transmed Gas Pipelines. The system has proved to be a cost-effective and flexible alternative to conventional technologies for free-span support, especially in deep waters. A cost/benefit analysis also shows the break-even point of the new technology vs. gravel dumping.
Gas Lifting a Major Oil Field in Argentina With High CO2 Content Associated Gas
Authors: Blann J. R. , Laville G. M.
Published: December 2007

The El Trapial Field in the Neuquen Province of Central Argentina produces more than 55,000 BOPD after 4 years of operation. The associated gas produced at El Trapial contains as much as 75% CO2. Immediately after the discovery of the field, a study indicated that gas lift would meet environmental concerns and be an attractive economical alternative for producing the field. The study also concluded that the high CO2 fraction gas dissolved in the oil could be used satisfactorily for gas lift purposes. A plan was implemented at that time to design and construct the production facilities around gas lift as the primary artificial lift method. This paper addresses special precautions required for design of the production and gas lift facilities to gas lift successfully with high acid content associated gas. Also discussed is Petrolera Argentina San Jorge's experience with such a system at El Trapial during the first 2 years of operation.
Novel Techniques Show Links between Reservoir Flow Directionality, Earth Stress, Fault Structure and Geomechanical Changes in Mature Waterfloods.
Authors: Heffer Kes J. , Fox Richard J. , McGill Colin A. , Koutsabeloulis Nick C.
Published: December 2007

Recent studies have revealed a strong correlation between the directionality of reservoir flow in waterfloods and the local orientation of horizontal earth stresses. Field applications are described of a novel technique of determining interaction between wells as a potential indicator of flow directionality. This technique calculates the Spearman rank correlation coefficient between flow rates at pairs of wells. These applications have demonstrated that the reservoir dynamics associated with correlated rate fluctuations have at least some component coupled to geomechanics. Coupled geomechanical-fluid flow numerical modelling is able to explain some of the observations and offers an improved predictive tool for planning and managing waterfloods and determining optimal locations for infill wells.
Pattern Modification by Injection-Well Shut-ln: A Combined Cost-Reduction and Sweep-Improvement Effort
Authors: Collings R. C. , Hild G. P. , Abidi H. R.
Published: December 2007

The Rangely Weber Sand Unit is a mature giant oil field that is currently under tertiary recovery with CO2. The Rangely oil field has been developed in stages, as have most large oil fields. This staged development over 50 years has had a significant impact on the distribution of remaining movable oil. Simulation studies indicated that oil cut could be improved if injection patterns were modified by shutting in injection wells to take advantage of relative well maturity. A field pilot project based on these studies has yielded results that indicate improved economic performance because of lower operating costs related to improved oil cut and reduced well maintenance.
Gravel Placement in Horizontal Wells
Authors: Penberthy W. L. , Bickham K. L. , Nguyen H. T. , Paulley T. A.
Published: December 2007

Long, horizontal gravel packs are viable completions that have been placed successfully in more than 80 wells. Extensive field-scale testing has significantly aided the development of field procedures and operating guidelines. Software has also been developed to assist with horizontal gravel-pack design. To be performed properly, these completions require a systems approach for their implementation because drilling and displacing the completion interval, maintaining hole stability, selecting and running equipment, and maintaining returns during the gravel-packing operation must be integrated into the completion strategy. Field experience suggests that, in some cases, gravel packs maintain productivity better than prepacked screens or slotted liners.
Reduction in Fatigue Failures Through Crack Detection by Alternating Current Field Measurement
Authors: Gaynor T. M. , Roberts D. L. , Homan E. , Dover W.
Published: December 2007

Once a crack is initiated by cyclic stress in a drillstring component, it will grow under further service loading and will fail when insufficient uncracked material remains to carry the applied load. Because the levels of cyclic and subsequent stress in drilling may be unknown (or unknowable), the drilling equipment supplier's main defense against component fatigue failure (after design) is detection of the initial crack, conventionally by magnetic-particle or dye-penetrant inspection (respectively, MPI or DPI).

A clean bill of health from MPI or DPI means only that no crack indications were found. The likely locations of cracks (e.g. thread roots in box connections) are often difficult to examine. Detection and interpretation are subjective and depend on the skill of the inspector. A crack and a surface defect may be indistinguishable from one another. No reviewable evidence of component inspection is left to allow an audit of inspection previously performed.

Alternating current field measurement (ACFM) induces a current in the surface of a component. If ACFM detects a perturbation in the magnetic field created in the free space above the surface, a surface defect is present. ACFM is able to determine the length and depth of a defect. It does not require a clear line of sight between operator and crack location. All data are recorded electronically and the evidence for the existence or nonexistence of a crack can be revisited.

The paper describes the theory of the technique, the equipment used, and practical results from the first application of ACFM to downhole motor components.
Newly Applied BHA Elements Contribute to Mainstreaming of Coiled-Tubing Drilling Applications
Authors: Gleitman D. D. , Hardin J. R. , Hightower C. M. , Gantt L. L. , Smith B. E. , Upchurch E. R. , Smith M. B.
Published: December 2007

Coiled-tubing drilling (CTD) is coming into the mainstream in a number of locations and applications, and the availability of improved bottomhole assembly (BHA) elements is a significant contributor in this regard. This paper describes BHA elements, including a hydraulic orienter and measurement-while-drilling (MWD) system, recently used by Arco in CTD operations; examines their capabilities; and provides examples in which these tools were used successfully.

The BHA orienter is a newly engineered, simple, hydraulically actuated device. This paper examines its performance attributes affecting overall rate of penetration (ROP) and directional control of the BHA, including its actuation speed and its ability to change the BHA orientation while in a medium-radius curve. The MWD system represents a new application of an existing reliable system, with attributes that are especially important in the CTD environment. Modifications related to downsizing are examined, as well as relevant performance attributes including steering-data-update rate; real-time gamma log quality; mud-pulse-detection capability on coil in a range of drilling fluids; and reliability. The BHA is also looked at from an overall system perspective, including its integration with the coiled tubing (CT) and other equipment associated with the CTD operation.

As of the writing of Ref. 1, Arco Alaska Inc. and THUMS Long Beach Co. (a wholly owned subsidiary of Arco) had completed 16 CTD re-entry sidetrack jobs in Alaska and Long Beach, California, with these BHA elements. This paper summarizes overall performance and reliability from these jobs. Additionally, specific cases are examined in greater detail, with these BHA elements contributing to successful CTD window milling, medium-radius curves, and laterals. (As of this publication, Arco companies have performed 47 such jobs with these BHA elements; however, this paper focuses on the first 16 jobs.)
Acid-Sludge Characterization and Remediation Improve Well Productivity and Save Costs in the Permian Basin
Authors: Wong T. C. , Hwang R. J. , Beaty D. W. , Dolan J. D. , McCarty R. A. , Franzen A. L.
Published: December 2007

Many oil wells in the Permian Basin have reported sludging problems associated with acid stimulations. The acid sludge is similar among wells and was identified as a viscous emulsion stabilized by asphaltene-rich organic solids. The sludging tendency of the oil increased with the concentrations of asphaltenes and resins, base number of the oil, and ferric ion content in the acid. Only three out of nine commercial acid systems tested were effective in preventing acid-sludge formation; they all use the same novel iron control technology, i.e., catalytic reduction of ferric ions. Several commercial and generic solvent systems were effective in dissolving acid sludge, including mixtures of an aromatic solvent (e.g., xylene) with either isopropyl alcohol (2:1 volume ratio), or ethylene glycolmonobutylether (EGMBE) (2:1 to 3:1 volume ratios). Selection of acid formulations and solvent systems was based on cost effectiveness and operation safety. Field implementation proved successful. If the results of this study had been implemented earlier in the lives of some of the Permian Basin properties, the recovery of 574 BOPD of lost or deferred production from 99 wells could have been realized. This would have resulted in an estimated increased revenue of over U.S. $3 million in 1 year.
Use of Preformed Gels for Conformance Control in Fractured Systems
Authors: Seright R. S.
Published: December 2007

Using wide ranges of gel age, gel velocity, and fracture conductivity or tube diameter, Cr(III)-acetate-HPAM gels were studied as they extruded through fractures and tubes. Gels exhibited shear-thinning behavior in fractures and tubes that correlated with the gel superficial velocity and the fracture width or tube diameter. In fractures with sufficiently small widths, gels dehydrated during extrusion, thus reducing the rate of gel propagation. This effect was more pronounced as the fracture width decreased. Using the experimental results, a numerical study was conducted to compare placement of preformed gels and water-like gelants.
Alkaline/Surfactant/Polymer Pilot Performance of the West Central Saertu, Daqing Oil Field
Authors: Shutang Gao , Huabin Li , Zhenyu Yang , Pitts M. J. , Surkalo Harry , Wyatt Kon
Published: December 2007

A tertiary pilot application of the alkaline/surfactant/polymer (ASP) process was initiated in Sept. 1994 in the west central area of Daqing oil field. The pilot pattern consists of four inverted five-spots, including four injectors, nine producers, and 2 observation wells, encompassing an area of 90 000 m2 and with a pore volume (PV) of 203 300 m3. The target layer is the Saertu II1.3 (SII1.3) sandstone, with an average porosity of 26% and permeability of 1.426 [m2. The crude-oil viscosity is 11.5 mPa • s at reservoir temperature and the connate-water salinity is 6800 mg/L. The pilot performance shows a pronounced response from ASP injection. The average pilot area oil production rate increased from 36.7 to 91.5 m3/d, while water cut decreased from 82.7% to 59.7%. For the central well Po5, which is surrounded by injection wells, the oil production rate increased from 3.7 to 27.1 m3/d, while water cut decreased from 84.0% to 45.8%. Numerical simulation results forecast that the oil recovery will be increased by 18.1% original oil in place (OOIP). Total pilot oil production as of March 1996 is 67 500 m3 of which 25 300 m3, or 18.3 % OOIP, is additional produced oil with the current oil cut of 29.7%.
Simulation of Cold Production in Heavy-Oil Reservoirs: Wormhole Dynamics
Authors: Tremblay Bernard , Sedgwick George , Forshner Ken
Published: December 2007

The laboratory investigation described arose from a need to observe more directly how sand production can lead to enhanced oil recovery during the cold-production process. The production of oil and sand into a perforation was simulated by use of a sandpack with an orifice at one end. The pack was imaged throughout the experiment with a computed-tomography (CT) X-ray scanner. The experiment showed that (1) stable wormholes can develop in unconsolidated oil sands, (2) they likely develop in the weaker sands (which normally contain the most oil) within a formation, (3) a critical flow rate is required for the wormholes to grow, (4) the high sand cuts observed in the field at the start of cold production indicate that the wormholes are growing, and (5) the decrease in sand production rate observed in the field indicates that the wormholes have stopped developing and are being emptied out by scouring.
Best Practice for the Distribution and Metering of Two-Phase Steam
Authors: Hong K. C. , Griston Suzanne
Published: December 2007

For a steamflood project to be successful, steam of predetermined quality and rate must be delivered to each injection well. This paper presents a comprehensive review of devices and methods that are aimed at providing accurate distribution and metering of two-phase steam. A best practice recommended for optimizing the distribution and metering process consists of several tools and procedures, including the following.

Using impacting tees, with or without insert devices, to maintain uniform steam quality throughout a piping network. Controlling the steam rate at each wellhead using a critical flow choke, with a straight-bore or tapered-bore bean insert. Periodically measuring steam rate and quality at each injector using a two-phase separator vessel. Monitoring wellhead rates on a biweekly or monthly basis using measured steam temperatures upstream and downstream of the wellhead chokes.
Crossflow in Fractured/Layered Media Incorporating Gravity, Viscous, and Phase Behavior Effects
Authors: Dindoruk Birol , Firoozabadi Abbas
Published: December 2007

Crossflow across the interfaces of layered reservoirs, and between matrix blocks and fractures in fractured reservoirs may be very pronounced. The literature emphasizes viscous crossflow, however, crossflow due to gravity may be more significant.

In this paper, the crossflow due to various effects in layered and fractured media are presented. The examples selected for the layered media show that most of the oil is first transferred from the low permeability to the high permeability layer and then produced. The examples for fractured media reveal a significant contribution of crossflow to recovery performance. The fractured-media examples imply that a real challenge exists to perform compositional simulation of fractured reservoirs.
Heterogeneities Modeling and Uncertainty Quantification of the Gullfaks Sør Brent Formation In-Place Hydrocarbon Volumes
Authors: Linjordet Arne , Nielsen P. E. , Siring Erling
Published: December 2007

The Gullfaks Sør oil- and gas-filled Brent reservoir can be divided into 14 fault Segments, five of which are penetrated by wells that have proven hydrocarbon columns between 32 and 316 m. The uncertainties in gas and oil in-place volumes have delayed the time from discovery in 1978 to the current partial development plan that was submitted to the Norwegian authorities in 1995 for development of the oil reserves. This paper describes the method used for modeling fault-segment reservoir heterogeneities and the method of quantifying the distribution of oil and gas accumulations. The final product is the most likely stock tank oil initially in place/gas initially in place (STOIIP/GIIP) with reliable high- and low-volume estimates for management decision making.

We evaluated the initial reservoir fluid pressures and fault-sealing properties together with observed internal reservoir barriers to vertical fluid flow and several fluid-contact observations. We established a quantification of the oil-leg thicknesses, including uncertainty ranges, on the basis of the field gas- and water-pressure gradients and the fluid densities. This quantification had to honor the various fluid contacts, the fluid gradients, and log observations, such as water up to, gas down to, and geochemical core analysis.

We evaluated the degree of communication between drilled fault Segments by determining probabilities of static-pressure communication between the drilled and undrilled fault Segments and between the various reservoir units across the faults. We assessed communication of fluid flow across faults by evaluating the clay smear (amount of clay material in relation to the fault planes) and juxtaposition relations of the reservoir units across faults.

We used a Statistical approach to quantify the uncertainty in the proven and probable in-place Gullfaks Sør Brent formation hydrocarbon volumes for field-development decision making. A geostatistical program designed to handle laterally varying uncertainties was used for quantifying uncertainties in the seismic Interpretation, velocity model, depth conversion, isochores, and fluid contacts. To evaluate the petrophysical uncertainties and the probabilities for gas- or oil-filled reservoir Segments, we used a classical Monte Carlo Simulation method. The combined use of geostatistical analysis and Monte Carlo Simulation has proved to be a useful and fast approach for modeling the Gullfaks Sør field.
First Horizontal Water Injectors in Prudhoe Bay Field, Alaska
Authors: Bodnar D. A. , Clifford P. J. , Isby J. S. , Lane A. C. , Loveland Richard , Seymour L. I. , Urban D. M. , Shultz S. M. , Walz G. S.
Published: December 2007

Water injection into horizontal wells is a new and distinct technology, where success will often depend on the management of thermal fractures. This paper describes the background, planning, drilling, completion, and results of the first two high-angle water injection wells in the Prudhoe Bay field. The procedures described resulted in re-establishing injection in the correct zone, achievement of target rates and good injection profiles.
Composition and Phase Changes in Testing and Producing Retrograde Gas Wells
Authors: Novosad Zdenka
Published: December 2007

Depletion of two retrograde gas reservoirs is analyzed with a compositional simulation model, focusing on changes in well performance caused by liquid dropout. In one case presented, a low-permeability reservoir at its dewpoint, transient effects are shown to contribute more to well productivity decline than liquid dropout. This is demonstrated by comparing the well productivity with that of an otherwise identical dry gas well. The evolution of the near-well liquid bank is interpreted in terms of compositional changes occurring in the fluid once the flowing bottomhole pressure falls below the dewpoint. The thermodynamic path of depletion is shown to be a function of radial distance (i.e., the pressure regime), and to be considerably more complex than implied by constant volume depletion (CVD) experiments. Near-well fluids undergo a transition from a retrograde gas to a volatile oil early in the depletion, passing through a critical composition in the process. This brings about large changes in phase properties and their saturations, and thus flow behavior, with even a small pressure change. This has implications for interpretation of pressure buildup and falloff tests on these wells. At a later stage in the field life, near-well fluids are converted from a volatile oil to a dry gas (passing through a critical composition again). With time, fluids in the reservoir interior undergo similar qualitative changes. Only the fluids near the reservoir edge follow a CVD path. The described phenomena are shown to occur in a higher-permeability reservoir also as soon as the bottomhole flowing pressure (BHFP) falls below the saturation pressure.