bluuebunny/crossref_metadata_2025 huggingface dataset:
Evaluation of Multiphase Flow Rate Models for Chokes Under Subcritical Oil/Gas/Water Flow Conditions
Authors: Schüller R. B. , Solbakken T. , Selmer-Olsen S.
Published: December 2007

Knowing the mass flow rate is important in relation to production control in the oil and gas industry. If the change in pressure and temperature across a choke can be correlated with the mass flow rate, the actuator position, and the properties of the well stream, this may constitute a mass flow rate meter that is both simple and inexpensive compared to other designs. However, knowledge of the predictive ability and accuracy of available mass flow rate models is required to qualify such a solution. Predictions from several mass flow rate models are compared with data from a crude oil/natural gas/water system at pressures varying from 8 to 16 bara. The fluids used were recombined oil from the Njord field in the North Sea, natural gas from the Kaarstoe terminal in Norway, and water with added salts to give typical produced-water properties. Two different choke geometries (orifice and cage type) were tested for three different opening areas. The experimental results are compared with eight mass flow rate models for multiphase flow through chokes. These are the two Hydro models originally developed by Selmer-Olsen, the Sachdeva et al. model, the Perkins' model, and four two-phase multiplier models—the Morris, the Chisholm, the Simpson, and the homogeneous equilibrium model (HEM), respectively. For the orifice-type geometry, the Hydro short model predicted the results most accurately. For the cage-type geometry, the Hydro long model, which includes losses in the choke geometry, predicted the results most accurately. A modification to the slip model improves the results of the Hydro models, predicting all the 367 test points with a standard deviation of 7.8%. The average error of absolute values was 5.8%.
Occurrence, Prediction, and Prevention of Zinc Sulfide Scale Within Gulf Coast and North Sea High-Temperature and High-Salinity Fields
Authors: Collins I. R. , Jordan M. M.
Published: December 2007

In oil and gas production operations, precipitation of mineral scales causes many problems, such as formation damage, production losses, increased workovers in both producers and injectors, poor injection-water quality, and equipment failures caused by underdeposit corrosion. The most common mineral scales are sulfate- and carbonate-based minerals. However, scale problems are not limited to these minerals, and there recently have been reports of unusual scale types, such as zinc and lead sulfide. This paper focuses on zinc sulfide scale that has been found in several fields along the Gulf Coast of the U.S.A. and in fields within the North Sea Basin. Scale deposition has caused significant pressure and rate reductions in high-temperature and high-rate gas, condensate, and black oil wells. After acid washes to remove zinc sulfide scale (and other acid-soluble solids), production rates and flowing tubing pressures returned to previous levels, but new scale deposits formed in many wells and retreatments were required. Topside process equipment, most noticeably low-pressure separators and hydrocyclones, were observed to suffer reductions in performance owing to zinc sulfide scale deposition. In addition, there are significant risks associated with acid treatments in high-temperature, high-pressure (HT/HP) gas wells in corrosivity of the acid at high temperatures (general corrosion, sulfide stress cracking, and chloride stress cracking) and in safety (hydrogen sulfide generation by acid dissolution of zinc sulfide plus high-pressure pumping). One possible method for preventing production declines and reducing the need for HT/HP acid jobs is to use scale inhibitors or chelating agents to prevent the formation of zinc sulfide scale. The relative effectiveness of eight scale-inhibitor chemistries and two chelating agents in preventing formation of zinc sulfide scale has been determined. The required scale-inhibitor concentrations are significantly higher than those needed for common sulfate and carbonate scales. For chelating agents, it is possible to prevent the formation of zinc sulfide scale when the required concentrations are proportional to the zinc ion concentration in the scaling brine. This paper outlines the testing methods used for chemical screening and prediction so that assessment of the potential problem within fields can be assessed during appraisal, before production commences, making a method of managing the risk available.
Statistical Assessment and Management of Uncertainty in the Number of Electrical Submersible Pump Failures in a Field
Authors: Sawaryn S. J. , Ziegel E.
Published: December 2007

Successfully managing a population of electric submersible pumps (ESPs) requires an accurate estimate of the expected number of failures as a function of time plus a determination of the associated uncertainty. Knowledge of the uncertainty is required for an effective risk assessment to be made of workover strategies and the impact of these on production economics. Though the oilfield literature contains discussions of the models and methods for estimating the expected number of ESP failures, little discussion has been presented on the confidence of such estimates.

This paper contains details of how the choice of model, parameter estimates, and variations in a well's economic criteria affect the confidence limits. It shows that the uncertainties inherent in continuously replacing ESPs and estimating their run lives may make the estimates of the number of failures across an entire field considerably uncertain. This effect is particularly pronounced during the first few years after field startup. Under these circumstances, the distribution of the number of failures is skewed, and a 60% difference between the estimated and recorded number of failures is possible. Statistical models also enable differentiation in performance between manufacturers and technologies. It is shown that even large differences in the measured run life may not be conclusive evidence of technical or manufacturing superiority. Based on these results, actions are suggested to reduce the uncertainty and improve the management of a field.
Predicting Brine Mixing Deep Within the Reservoir and Its Impact on Scale Control in Marginal and Deepwater Developments
Authors: Mackay E. J. , Jordan M. M. , Torabi F.
Published: December 2007

Sulphate scale deposition is a common problem in hydrocarbon reservoirs in which injection seawater that is rich in sulphate mixes with formation brines that are rich in barium, strontium, and calcium. Deposition of these scales can cause significant production impairment if it occurs within zones near the production wellbores. To control scale deposition in the near-wellbore region of a reservoir, scale squeeze treatments are commonly deployed. In cases in which scale severity is very high, removal of sulphate ions from the injection water is an alternative scale-control strategy. Both these mitigation methods have associated capital (CAPEX) (e.g., desulphation plant) and operating expenditures (OPEX) (e.g., scale squeeze treatments).

To assess the severity of the problem in new fields, thermodynamic calculations typically are performed to calculate the mass of scale that will form. Until recently, little work has been carried out to identify the location of scale formation within the reservoir. In this paper, field data and flow simulations from three North Sea fields are presented to show that scale formation can, in fact, occur deep within the reservoir and can have a negligible negative impact on oil production in the near-wellbore region.

Evidence is presented from these North Sea fields that shows the evolution of the brine chemistry as seawater breakthrough occurs and as squeeze treatments are applied. The evidence from the produced brine chemistry is linked to flow calculations for these fields to show that in some systems scale is depositing deep within the reservoir, reducing the potential for damage in the near-production wellbore region. The extent and impact of the deposition varies throughout the reservoir and can be quantified. Modeling brine mixing and stripping of the scaling ions before the fluids reach the production wellbore has a significant impact on the economic assessment of marginal fields and deepwater developments. In such fields, the technical challenge and cost (CAPEX/OPEX) of scale control might make development uneconomical. This paper outlines the data requirements and methodology used to allow such an assessment to be made.
A New Comprehensive, Mechanistic Model for Underbalanced Drilling Improves Wellbore Pressure Predictions
Authors: Pérez-Téllez C. , Smith J. R. , Edwards J. K.
Published: December 2007

A new comprehensive, mechanistic model that allows more precise predictions of wellbore pressure and two-phase flow parameters for underbalanced drilling (UBD) is proposed. The model incorporates the effects of fluid properties and pipe sizes and, thus, is largely free of the limitations of empirically based correlations.

The model is validated against actual UBD field data and fullscale experiments in which the gas and liquid injection flow rates as well as drilling fluid properties were similar to those used in common UBD operations. Additionally, a comparison against two different commercial, empirically based UBD simulators shows better performance with the mechanistic model.
On the Calibration of Design Collapse Strengths for Quenched and Tempered Pipe
Authors: Adams A. J. , Moore P. W. , Payne M. L.
Published: December 2007

The joint API/ISO Work Group 2b under Steering Committee 5 (SC5) for tubular goods is currently rewriting API Bull. 5C3/ISO 10400 for casing and tubing performance property equations. This paper describes the proposed new treatment for collapse of quenched and tempered (Q&T) pipe.

The work is still in progress, and the final text has yet to be agreed upon, but the present results are considered reasonably mature and have been circulated as a committee draft for international comment.

Committee work has shown that the current (sixth edition) rating equations give highly variable risk over the Do/t range for downhole well tubulars, whereas the proposed new equations give nearly uniform risk. Different ratings are proposed for cold- and hot-straightened pipe. Overall, they result in minor cost savings with respect to the sixth edition of API Bull. 5C3 collapse strengths.
The Wilson Creek Field, Rio Blanco County, Colorado
Authors: Ladd J.B.
Published: December 2007

The Wilson Creek field is situated in mountainous terrain of Rio Blanco County, Colo. It was discovered in early 1938 and produces from both the Morrison and Sundance sands of Jurassic age. The underlying Sundance reservoir is fully developed with 18 wells; no dry holes have been drilled. The overlying Morrison reservoir of greater areal extent is almost completely developed with 21 producing wells and three dry holes around the periphery of the field; in addition, all or most of the 18 inside Sundance wells will eventually serve to exploit the central portion of the Morrison reservoir.

The Morrison reservoir was moderately undersaturated with an initial average pressure of 2,180 psig and a bubble point pressure of about 1,100 psig; a partial water drive is in effect. A top structure gas injection program was started early in the life of the pool, resulting in a dampened pressure decline rate and increased oil recovery.

The Sundance reservoir is greatly undersaturated and exhibits a prolific water drive. Individual well fluid capacities are generally high and edgewater-type encroachment is evident throughout all producing levels. A down-flank gas injection project has recently been instigated.

The field is completely electrified and power is generated in a field plant. The operators own and maintain an 18-mile pipeline through which over 7,000 BOPD may be shipped by gravity flow. Major operational problems are related to extended winter periods of extreme cold and deep snow, rough terrain, paraffin accumulations, water disposal, and high water:oil and gas:oil ratio control.

Introduction

The Wilson Creek field is located on the northern edge of Rio Blanco County, Colo., about 25 miles southwest of Craig, the only railhead in the area, and 10 miles north of Meeker. For geographical orientation see Fig. 1. The local terrain is mountainous, being in the more rugged portion of the regional Danforth Hills anticlinical trend. It is readily accessible year-around via well-maintained county roads connecting the local federal and state highway system.
The Heather Platform Leg Repair
Authors: Thompson J.M. , White A.R.
Published: December 2007

This case history reviews the analysis and repair of a corner leg of the Heather A platform; damage was caused by a foundation pile dropped during installation. The paper describes the stereophotographic and mechanical templating techniques used to verify shell deformations. The choice of a mechanical solution and the interface with module installation and commissioning are reviewed.

Introduction

The Heather field is located in Block 2/5 of the U.K. sector of the North Sea (Fig. 1). The Heather A platform is located at 0 degrees 56'22.53" longitude and 60 degrees 57'13.51 "latitude, approximately 100 km (64 miles) east of the northern end of the Shetland Islands in 143 m (470 ft) of water. The oil field was discovered in Dec. 1973, and a steel-pile-supported platform was selected to develop the discovery. With the availability of larger pile-driving hammers, the decision was made in the fall of 1975 to drive 1.52-m (60-in.) diameter piles. Each of the 24 piles [96 m long × 64 mm thick (315 ft × 2.25 in.) and 218 Mg (240 tons)] is made from a 64-m (210-ft) lead section with a 32-m (105-ft) extension welded offshore. During the offshore piling operations in the summer of 1977, one of the piles had been joined and was being held by the derrick barge in preparation for lowering to the seabed, then one of the shackles linking two sections of slings broke. The pile, laterally restrained in the guides, dropped more than 40 m (130 ft) in almost free vertical fall before hitting the jacket at the location shown in Fig. 2.The extent of the damage posed a potentially serious setback to field development. With the reduction of load-carrying capability of the platform, the complete module installation program was reanalyzed. The selection of the repair method was judged in line with performing the repair during the winter period. A limited number of modules were installed on the platform by mid-Oct. 1977, when the repair operation commenced from the semisubmersible vessel Treasure Hunter. The first phase of the repair was completed by mid-Jan. 1978, and the second phase from mid-April to the end of May finalized the repair.This paper traces the stages of design, repair, and techniques developed and appraises the interface with the remainder of the development.

Description of Damage

Initial impact of the pile was at the cone-shaped section of the "bottle" where the leg diameter increases from 2.5 to 5.7 m (8 to 18.5 ft). The pile glanced off the cone, buckling the 40-mm (1.625-in.) thick plate and punching a hole [approximately 1.25 × 1 m (4 × 3.5 ft)] in the cylindrical shell. At the junction of the cone and shell is a critical ring stiffener designed to contain the hoop stresses at this change in section. This ring stiffener was torn in two places, and the tongue section in between was bent downward. As the pile fell, it continued to dent the cylindrical shell up to 200 mm (10 in.) radially and caused further damage to a second lower ring stiffener. Denting of the vertical shell was caused over some 4.5 m (14.5 ft).

JPT

P. 569＾
New-Generation Drillstring Safety Valves
Authors: Tarr B. A. , Luy R. , Rabby G. , Kickermann H. , Senftleben J. , Cunningham J.
Published: December 2007

Drillstring safety valves (DSSVs) are considered an essential part of the well-control equipment on every rig, but performance problems in stripping operations motivated one operator to lead an industry effort to develop appropriate functional specifications for consideration by API and to conduct the associated performance testing described in this paper. Results of testing three different valves indicate that common DSSV performance problems can be addressed and that the proposed new performance specifications for a new generation of DSSVs are generally workable.

API subsequently incorporated many of the proposed changes into the 40th edition of API Spec. 7, identifying the new-generation valves as Class 2 valves suitable for surface and downhole (stripping) service.
The Arctic Pilot Project
Authors: Milne K.C.
Published: December 2007

This paper describes the proposed Arctic Pilot Project, consisting of transmission, liquefaction terminal, shipping, and receiving terminal. Emphasis is on the unique problems resulting from the arctic location. Studies conclude that it is feasible to transport gas on a year-round basis from the arctic to the Canadian east coast.

Introduction

The Arctic Pilot Project proposes to transport 250 MMscf/D (7 × 10(6) m3/d) of gas from Melville Island in the Canadian arctic to markets in eastern Canada. The gas will be pipelined from the Drake Point gas field to Bridport Inlet on the south coast Point gas field to Bridport Inlet on the south coast of Melville Island, where it will be liquefied and loaded on ice-breaking LNG carriers for transportation to a regasification terminal in eastern Canada.The economical and environmentally sound transportation of gas from the arctic revolves around the answers to two important and basic questions.1. Can the Melville Island facilities be built on an economical and environmentally sound basis given that the location could be expected to result in conventional facilities that would cost at least five times that of facilities built in settled areas?2. Can large ice-breaking LNG carriers operate year round in the arctic waters leading to Bridport Inlet?Petro-Canada, The Alberta Gas Trunk Line Co. Ltd. (AGTL), and Melville Shipping Ltd. have spent more than $11 million and 2 years finding the answers to these two questions and have concluded that the project is feasible, that the capital cost will be about $1 billion, and that the gas will be delivered to southern markets at a competitive price.

Melville Island Facilities

These facilities include the gas transmission line across Melville Island, the floating LNG plant and storage, and the Bridport shipping terminal.The lack of site specific information, which increases uncertainties in scope definition, and the high cost of on-site labor result in (1) arctic construction costs (using conventional methods) that are at least five times the costs in settled areas; and (2) a high degree of uncertainty in estimating final cost. The cost of on-site labor for this project will be minimized by building facilities to the greatest extent possible in settled areas. This approach minimizes the possible in settled areas. This approach minimizes the environmental and socioeconomic impact on the arctic.

Gas Transmission

The proposed gas transmission line is a 95-mile (160-km), 22-in. (560-mm) buried chilled gas line. This size line has a calculated capacity of 336 MMscf/D (9.54 x 10(6) m3/d) at the design inlet and outlet pressures of 1,200 psig (8268 kPa) and 900 psig (6200 pressures of 1,200 psig (8268 kPa) and 900 psig (6200 kPa).The cost estimate was prepared by AGTL, assisted by Canuck Engineering Ltd. The costs were based on proved construction techniques such as those used in proved construction techniques such as those used in the permafrost sections of the Aleyeska pipeline. The estimators have assumed construction only in the months of April, May, September, and October.

JPT

P. 351
Permanent Mooring System for Large Construction and Support Vessels in the Piper Field
Authors: Lowe E.A. , Yin V.C.
Published: December 2007

This paper illustrates the requirement, design, development, and installation of a permanent mooring system for construction support vessels in the Piper field in the North Sea. Key features of the mooring system and its installation procedures are detailed.

Introduction

The need for support vessels alongside the platform during construction programs offshore has focused attention on the problems of mooring and maintaining station in this service. In the past, mooring systems under storm situations have been designed primarily for open-ocean applications and have not primarily for open-ocean applications and have not catered to the requirements of operating and surviving alongside a fixed platform. In addition, anchor handling and dragging have been primary causes of damage to submarine pipelines. This problem becomes more acute as the number of problem becomes more acute as the number of vessels around the platform increases and the number of moorings over time becomes significant enough to constitute a hazardous situation.The Piper field operators - Occidental of Britain Inc. on behalf of partners Getty Oil Co., Allied Chemical (Great Britain) Ltd., and Thompson North Sea - experienced these mooring difficulties, compounded by poor topsoil conditions, which led to the design and installation of a fixed, permanent anchor-pile mooring system around the Piper A platform. platform. System Description

Eight anchor piles are positioned symmetrically around the Piper A platform to provide a suitable anchor pattern for a multiservice construction vessel to moor alongside the platform in periods of good weather and away from the platform in periods of bad weather. Each anchor pile is approximately 4,000 ft (1219 m) from the center of the platform, and the 1,010-ft (309-m) connecting chain lies on the seabed in a straight line between the anchor pile and the platform. The free end of each chain is connected to a pendant line and marker buoy, which is used to raise the free end of the chain to the surface during connecting or disconnecting operations (Fig. 1).

System Capabilities

The anchor-pile system is designed to accommodate construction and tender vessels ranging from medium-sized to third-generation semisubmersibles with operating draft displacements in excess of 40,000 Mg. This system allows for vessels to moor on any of the four sides of the platform and maintain adequate clearance of the mooring catenary from the legs of the platform jacket. The vessel anchor line is "shackled up" to the anchor pile, making it a semipermanent connection. These piles are able to withstand vertical and horizontal forces, thus allowing for adequate "spring constants" throughout the vessel excursion distance even after introducing uplift forces at the anchoring point.

System Design Mooring System

The mooring system consists of eight anchor piles encircling the platform.

JPT

P. 547
Engineering Calculations of Gas-Condensate-Well Productivity
Authors: Mott Robert
Published: December 2007

Accurate forecasting of gas-condensate-well productivity usually requires fine-grid numerical simulation to model the formation of the condensate bank and to account for high-velocity phenomena such as non-Darcy flow and changes in relative permeability at high capillary number.

This paper presents a new technique for forecasting the performance of gas-condensate wells, using simpler techniques that can be used in a spreadsheet. The calculation uses a material-balance model for reservoir depletion and a two-phase pseudopressure integral for well inflow performance. The pseudopressure-integral technique has been extended to include high-velocity effects and to allow for the change in produced-fluid composition caused by the formation of the condensate bank.

The new technique has been tested by comparison with the results of fine-grid compositional simulation, and the results are in good agreement for a wide range of cases covering vertical, horizontal, and hydraulically fractured wells.

The spreadsheet-model approach provides a useful tool for rapid forecasts of condensate-well performance, for examining the effects of condensate blockage in different well types, or for studying sensitivities. It is also valuable where simple models of condensate-reservoir performance are required for use in integrated studies involving issues such as surface facilities, drilling schedules, and gas sales contracts.
Estimation of True Dispersivity in Field-Scale Permeable Media
Authors: Mahadevan Jagannathan , Lake Larry W. , Johns Russell T.
Published: December 2007

Simulation studies (Solano et al.1; Stalkup2) show that oil recovery for enriched gas drives depends on the amount of dispersion in reservoir media, but the value of dispersion, expressed as dispersivity, is unknown at the field scale. This work focuses on three types of dispersion in permeable media to obtain realistic estimates of dispersive mixing at the field scale.

The dispersivity from single-well tracer tests (SWTTs), also known as echo dispersivity, is dispersivity that is unaffected by fluid flow direction. Layering in permeable media tends to increase the dispersivity observed in well-to-well tracer tests, also known as transmission dispersivity, but should not affect the echo dispersivity.

We analyzed a collection of SWTT data to estimate echo dis-persivity at the SWTT scale. The estimated echo dispersivities closely match a published trend with length in dispersivities obtained from groundwater tracer tests. This unexpected result—it was thought that transmission dispersivity should be greater than echo dispersivity—is analyzed with numerical simulation.

Another type of dispersive mixing is local dispersivity, or the mixing observed at a point as tracer flows past. Numerical simulation results show that the local dispersivity is always less than the transmission dispersivity and greater than the echo dispersivity. It is closer to one limit or the other depending on the amount and type of heterogeneity, the autocorrelation structure of the medium's permeability, and the lateral (vertical) permeability. The agreement between the SWTT echo dispersivities and the field trend suggests that the field data are measuring local dispersivities. All dispersivities appear to grow with length.
Profitability of Capital Expenditures for Development Drilling and Producing Property Appraisal
Authors: Arps J.J.
Published: December 2007

The appraisal of producing properties and profitability analysis of a proposed capital expenditure are based on the same principles. In both problems a projection of future cash income is compared to one or more capital expenditures. Several different methods have been in use either to compute a price to obtain a given earning power on the investment or to compute the earning power which will result from a given capital expenditure. One of these, the "Average Annual Rate of Return" method, computes in a simple manner the ratio of the present value of the future earnings after amortization to the present value of the undepreciated balances of the investment over the life of a project. This method, not well known generally, appears to have some rather unique advantages in reducing the computation work required, eliminating trial-and-error solutions, and providing a more accurate answer when applied to oil industry investments subject to the unit-of-production basis of amortization. Its derivation is given and its versatility demonstrated in the solution of certain everyday investment problems. A number of charts, useful in applying this method to profitability analysis and appraisal work, are provided. The current trend in the market values of producing properties is shown.

Introduction

Making sound capital expenditure decisions requires an objective means of measuring the productivity of individual investment proposals. Since the best measure of the economic worth of such proposals is their ability to produce profits, it is common practice to grade proposed capital expenditures according to their annual earning power as a percentage of the outstanding capital. The same principles which govern the determination of the rate of return of proposed capital expenditures also apply generally to the problem of determining the appraisal value or purchase price of income-producing oil and gas properties.

Both problems are of prime importance in the producing phase of the oil business, where management is faced daily with decisions to drill or not to drill certain development wells, or with the determination of the appraisal value of producing properties.
Downhole Fiber-Optic Flowmeter: Design, Operating Principle, Testing, and Field Installations
Authors: Kragas Tor K. , Bostick F. X. , Mayeu Christopher , Gysling Daniel L. , van der Spek Alex M.
Published: December 2007

This paper discusses the design, operating principles, flow-loop testing, and initial field installations of the world's first all-fiberoptic flowmeter for downhole deployment. The flowmeter provides real-time measurement of the flow rate, phase fraction, pressure, and temperature. It is deployed with the production tubing and is rated to 125°C and 15,000 psi. It is fullbore, nonintrusive, electrically passive, has no moving parts, and overcomes the design limitations imposed by downhole environments. Thus, it has the potential to provide highly reliable downhole measurements. The flowmeter has been tested extensively in industrial flow loops in a wide range of conditions. Results from the testing have demonstrated the flowmeter's ability to measure flow rates and water fractions in oil/water systems to within ±5% for the entire range of water cuts. These results have been validated by data from several field deployments.
Drag Reduction in Three Distinctly Different Fluid Systems
Authors: Sifferman Thomas R. , Greenkorn Robert A.
Published: December 2007

Drag reduction was observed in three distinctly different flow systems—dilute polymer solutions, two-phase solid/liquid suspensions, and three-phase immiscible liquid/liquid flow with suspended solids—in relatively large-diameter pipes (0.027, 0.038, and 0.053 m). Galvanized pipes presented a rough wall, while glass provided a smooth wall and allowed for flow visualization. By drag reduction, we mean that, for the same flow rate, there is less pressure drop per length of pipe than for the base fluid flowing alone.

Three polymers—sodium carboxymethylcellulose (CMC), polyethylene oxide (POLYOX™), and guar gum (Jaguar™) were mixed with water to form solutions of various concentrations (from 0.001 to 0.3 wt%). Two nominal concentrations (5 to 10%) of silica sand also were suspended with either tap water or some of the polymers. Finally, white mineral oil and either tap water or polymer solutions were tested. Sand also was added to the oil system.

Drag reductions of up to almost 80% were obtained for both the polymer systems and the oil system. Sand suspensions had a maximum of about 35% drag reduction in tap water. However, greatest reductions (more than 90%) were attained with the polymer/sand suspensions.

Since the sand in the polymer solutions reduced the drag even more than the polymers alone, it may be that the drag mechanism is additive and even may be the same type for both polymers and suspensions.

Drag reduction occurs in the region near the wall and could occur in an intermediate layer or zone that allows an effective slip velocity to result. Polymers showed significant deviation from the Newtonian velocity profiles.

Less power was required to pump the polymers than water alone. Viscosity and normal stress data were obtained also.
An Experimental Study of Drag Reduction of Polymer Solutions in Coiled Tubing
Authors: Shah Subhash N. , Zhou Y.
Published: December 2007

The drag-reduction (DR) behavior of xanthan gum, partially hydrolyzed polyacrylamide, guar gum, and hydroxyethyl cellulose at various polymer solutions has been experimentally investigated with a full-scale coiled-tubing (CT) test facility that consists of 1-, 1½-, and 2⅜-in. CT reels. Data analysis revealed that the tubing diameter, curvature ratio, and polymer concentration are important factors affecting the DR in CT. The modified DR envelope is a useful tool for evaluating the DR performance of polymer solutions in CT.
Fast Induction-Log Inversion Using Quasi-Newton Updates
Authors: Gao L.
Published: December 2007

Interpretation of induction-logging data is difficult because of its diffusive nature and its large volume of investigation. To overcome these difficulties, various techniques have been applied in the past. These techniques include deconvolution filters, least-squares inversion based on the maximization of entropy and on neural-network techniques. Among them, the maximum-entropy method is the most robust. Unfortunately, it is computationally intensive and can only be carried out in computing centers. To reduce this intensity and accelerate the inversion process, a new method has been developed for induction-log inversion using quasi-Newton updates of the Jacobian matrix. Using the new method, 200 ft of log data can be inverted in 80 seconds on an 800-MHz notebook computer.
Application of Water Injection/Falloff Tests for Reservoir Appraisal: New Analytical Solution Method for Two-Phase Variable Rate Problems
Authors: Levitan Michael M.
Published: December 2007

The challenges of reducing or eliminating emissions associated with well-testing operations during reservoir appraisal have revived interest in water injection/falloff tests. However, the two-phase flow and injection-induced temperature changes associated with injection/falloff tests complicate the problem of well-test analysis. Strictly speaking, these effects make the pressure transient problem nonlinear and preclude using conventional superposition technique to construct solutions for variable rate problems.

In this paper, we present a new analytical method for accurate solution of the pressure transient problem for two-phase flow associated with water injection/falloff tests. The solution algorithm allows one to compute the solution for any stepwise constant rate sequence that includes multiple injection and falloff periods. The method is general, and can be used for water injection governed by any physically meaningful relative permeabilities, as well as for pistonlike displacement.
Analytical Theory of Coalbed Methane Recovery by Gas Injection
Authors: Zhu Jichun , Jessen Kristian , Kovscek Anthony R. , Orr Franklin M.
Published: December 2007

Injection of either carbon dioxide (CO2) or nitrogen (N2) enhances recovery of coalbed methane. In this paper, we provide new analytical solutions for the flow of ternary gas mixtures in coalbeds. The adsorption/desorption of gaseous components to/from the coalbed surface is approximated by an extended Langmuir isotherm, and the gas-phase behavior is predicted by the Peng-Robinson equation of state (EOS). Langmuir isotherm coefficients are used that represent a moist Fruitland coal sample from the San Juan basin (U.S.A.). In these calculations, mobile liquid is not considered. Given constant initial and injection compositions, a self-similar solution consisting of continuous waves and shocks is found. Mixtures of CH4,CO2, and N2 are used to represent coalbed and injection gases. We provide examples for systems where the initial gas is largely CH4, and binary mixtures of CO2 and N2 are injected. Injection of N2-CO2 mixtures rich in N2 leads to relatively fast initial recovery of CH4. Injection of mixtures rich in CO2 gives slower initial recovery, increases breakthrough time, and decreases the injectant needed to sweep out the coalbed. The solutions presented indicate that a coalbed can be used to separate N2 and CO2 chromatographically at the same time coalbed methane (CBM) is recovered.
Real-Time and In-Situ Detection of Calcium Carbonate Scale in a West Texas Oil Field
Authors: Smith J. K. , Yuan M. , Lopez T. H. , Means M. , Przybylinski J. L.
Published: December 2007

A novel technique has been developed to detect the onset and increase of calcium carbonate scale deposition from oilfield production fluids. This method uses an attenuated total reflectance (ATR) probe, called the scale sensor, to detect scale formation in situ. Because this method is based on existing technology and requires little supporting equipment, a simple, cost-effective monitoring device could be placed in many locations within a production system. This method could provide a system-wide, in-situ, real-time response to calcium carbonate scale formation at its earliest stages.

As a first step toward evaluating the effectiveness of this new technology, the scale sensor was field tested at a west Texas oil field. The scale sensor was observed to detect the deposition of calcium carbonate under static and flowing conditions in actual produced fluids. In the static tests, crude oil, suspended solids, and other endogenous materials did not affect the scale sensor's response. Under flowing conditions, like those found in the production flowlines at this west Texas oil field, scale sensor response was observed to correlate to the chemical injection rate of both the scale inhibitor and the dispersant. On the basis of the results from the scale sensor, the scale inhibitor's injection point will soon be moved to the wellhead.
Theoretical Description of a New Method of Optimal Program Design
Authors: Miska Stefan , Skalle Pål
Published: December 2007

Drilling hydraulics have considerable effect on the rate of penetration. Previous studies have examined this problem; however, the effects of differential pressure and reliability of pumping equipment usually were neglected. This paper gives a general description of hydraulic drilling parameters optimized when both these effects were considered. To derive the necessary conditions for optimal hydraulics a nonlinear programming method was applied.
Identification of Steam-Breakthrough Intervals With DTS Technology
Authors: Johnson D. O. , Sugianto R. , Mock P. H. , Jones C. H.
Published: December 2007

Steam breakthrough in producing wells can be very problematic. Not only can production drop drastically, but catastrophic failure events can occur; holes can be cut in tubulars, screens, and casing. Many of these events can result in loss of the borehole. Therefore, it is critical that the offending sand zone is identified quickly.

Many breakthrough-identification methods have been tried, including produced-well temperature, pulsed-neutron logging, and drilling observation wells to monitor zonal temperatures.

This paper discusses methods for installing optical fibers in oil and gas wells for distributed temperature sensing (DTS), the search to gain the considerable value offered by fiber-optic technology, and the development of an extremely cost-effective and accurate method that takes advantage of the power of DTS technology for determining steam breakthrough in producing wells.
Relative Permeability From Thermodynamics
Authors: Papatzacos Paul , Skjæveland Svein M.
Published: December 2007

A new theory is reviewed for single-component, two-phase flow in porous media. It integrates thermodynamics with fluid mechanics and includes wettability in the thermodynamic description. It does not make use of the relative permeability concept. Wettability is included through a function that is part of the input to the model, together with an equation of state. A dialogue between this new model and the existing one has been established with the purpose of obtaining some of the input functions of both models. First, we have used information available in the existing model so as to calculate the function necessary for the description of wettability in the new model. The new model then being complete, we use it to find the two central functions necessary to the existing model, the relative permeabilities. We show that these are well defined when flow is characterized as a traveling wave, and we give a formula for their calculation. The formula assumes that a capillary pressure correlation and an equation of state are known, in addition to a constant related to the thickness of the transition region between the two phases.
Solubility of Sulfur in Hydrogen Sulfide and Sour Gases
Authors: Brunner E. , Woll W.
Published: December 2007

In recent years the search for natural gas has yielded many reserves that contain high concentrations of hydrogen sulfide.1 Production of sour gas initially was on a limited scale but since has increased considerably as a result of price increases for fossil fuels. Substantial quantities of sulfur now are produced from the hydrogen sulfide in these natural gas sources.

In several of these natural gas fields – e.g., in Canada and north Germany – gas production is hampered severely due to the presence of elemental sulfur dissolved in the gas. The gas-bearing deposits are interspersed with elemental sulfur, which is dissolved to a greater or lesser extent in the sour gas, the solubility being strongly dependent on the pressure, temperature, and composition of the gas. It is well-known that the solubility of sulfur increases with increasing pressure, temperature, and hydrogen sulfide content. As a result of the geothermal temperature profile, the gas stream cools as it rises up the production tubing and there is a drop in pressure due to frictional effects. Consequently, the solubility drops and sulfur is deposited when the solubility limit is exceeded. The gases dissolved in the liquid sulfur – principally hydrogen sulfide and carbon dioxide – lead to a lowering of the freezing point. At temperatures between 393.15 and 373.15 K, the sulfur begins to solidify in the line, blocking the tubing and bringing gas production to a standstill.

To prevent such blockages, suitable solvents are pumped into the well via an annular space surrounding the production tubing to dissolve the sulfur, which then is carried to the surface with the gas stream. A discussion of the technological problems involved in this process is beyond the scope of this paper.
Practicalities of Detecting Faults From Buildup Testing
Authors: Earlougher R.C. , Kazemi H.
Published: December 2007

The influence of a sealing fault (and other linear discontinuities) on transient well tests is a widely discussed subject. The topic first was presented by Horner for pressure buildup testing. Fig, 1 illustrates ideal pressure behavior in a tested well near a fault. This figure is a schematic semilog plot that applies to any kind of single-well transient test; doubling of the straight-line slope is the key to the existence of a fault. The material presented in this paper applies to falloff and buildup tests. It does not paper applies to falloff and buildup tests. It does not apply to flowing-only tests, such as drawdown, injectivity, and multiple-rate flow tests. The information in this paper assumes horizontal radial flow in a homogeneous, unfractured reservoir and assumes that wellbore storage effects are unimporant.There an pitfalls in detecting faults (used here to mean any linear discontinuity) from pressure buildup and falloff tests that generally are not recognized. The reason is that flow time determines how much reservoir a test investigates. So, for a pressure buildup test, the flow time before shut-in determines if it will be possible to recognize a fault from buildup data. If flow time is long enough, then the shut-in time need only be long enough to obtain data that show the dope doubling. A shortflow time cannot be compensated for by a long shut-in time. Interestingly enough, the pressure behavior caused by a fault is such that if shut-in time is not long enough to show the double slope, it is possible to interpret the data incorrectly as indicating a small closed system rather than a large system with a nearby fault.Flow times too short to detect faults during buildup testing are particularly apt to occur in two common types of well testing. One is drillstem testing, which generally has a short flow period. The second is the testing of a gas well where no pipeline facilities are available, so a short flow period is used while the shut-in period may last weeks or months.The theory describing pressure behavior in a well near a fault is relatively simple. Fig. 1 shows pressure buildup curve shape and indicates that the pressure buildup curve shape and indicates that the second slope, m2, is twice the first slope, m1. From the first slope, one calculates skin factor and permeability. permeability. The doubling of the slope is a strict theoretical requirement and not an approximation.

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Handling Production-Data Uncertainty in History Matching: The Meren Reservoir Case Study
Authors: Kabir C. S. , Young N. J.
Published: December 2007

History matching reservoir performance ordinarily implies adjusting geologic and rock-fluid flow properties until a satisfactory match is attained between the observed and model responses. Property adjustments inevitably imply a trial-and-error approach.

Regardless of the approach used in any study, we presuppose the integrity of observed data. Unfortunately, measurements of gas and water do not have the desired precision when oil is the primary fluid of interest. For instance, when gas is flared, the quality of metering suffers. In some operations, withdrawal of small samples of a three-phase mixture near the wellhead becomes the sole basis for establishing water content in a production stream. These practices often introduce large uncertainty in the reported data of all three phases.

This paper explores how we dealt with some of these issues while attempting to match 30-year performance in the Meren field in offshore Nigeria. Results show that production data affected by wellbore mechanical problems can be diagnosed with log-log type curves. Furthermore, this work shows that discerning water cut from wellhead samples is prone to errors, and issues with wellbore flow calibration can lead to large uncertainties in performance prediction. Identification of various issues helped mitigate the risks, leading to successful infill wells as testified by their production performance.
Materials Approach to the Development of Oilwell Cables
Authors: Wargin Robert V.
Published: December 2007

This paper presents and explains a chronological sequence of tests to gain an understanding of materials and construction requirements of electrical power cables for submersible motor pump (SMP) systems. A variety of simulated and actual downhole tests was run to examine the effects of time and temperature on the physical properties of insulation and jacketing materials. Pressure cycling effects on construction also were determined. The knowledge gained was applied to the development of a commercial electrical power cable.
The Twist and Shear of Helically Buckled Pipe
Authors: Mitchell Robert F.
Published: December 2007

The effect of torque on buckling was first recognized while designing hollow propeller shafts for ships. If buckling could be caused by torque, then perhaps torque could be induced by helical buckling. This effect has not been extensively studied because the assumption has always been that the effect was too small to be of concern. This problem required an exact large-displacement solution to the helically buckled pipe because conventional small-displacement analysis has the built-in assumption that these effects are not important.

How significant are these effects? Lubinski et al.,1 in their paper on helical buckling, worked a sample problem of a squeeze cementing operation in 2⅞-in., 6.5-lb/ft tubing. The induced torque caused by helical buckling may exceed the makeup torque (in the range of 600 to 2,300 ft-lbf, depending on the grade) for large radial clearances, so induced torque in this problem may be high enough to break the connection!

This paper gives complete details for the torque and shear calculation in the Appendices. The body of the paper examines several typical tubing-load situations to evaluate the effect of induced torque and shear on a conventional design.