bluuebunny/crossref_metadata_2025 huggingface dataset:
Developing and Implementing a Failure-Analysis Process To Optimize Well-Servicing Operations
Authors: Yonke Charles Lwanga , Araujo F. G. , Koehler K. D. , Strawn T. T.
Published: December 2007

Breakthrough cost reductions can be achieved through the use of an effective failure-analysis and control process. In 1995, CalResources designed and implemented a root-cause failure-analysis process for well-servicing operations. Important elements of the process include a structured process flow, a six-step failure-analysis model, tools for failure control (databases of well-failure codes and pump details, pump application tables, well-servicing economics), and meaningful tracking measures with targets. This process has been a key strategy to reduce expenses and increase equipment run time. Well pulls decreased by 33% from the previous year, repeat pulls decreased by 42%, well-servicing expenses decreased by 16%, and producer run time increased by 15.5%. Process implementation was achieved through operator empowerment and buy-in. Empowerment was developed through knowledge, with formal and informal sessions serving as forums for continuous training, practice, and feedback. This paper outlines the elements of the failure-analysis process developed, and discusses the implementation steps that made it successful.
Does Gauge Placement Matter in Downhole Transient-Data Acquisition?
Authors: Kabir C. S. , Hasan A. R.
Published: December 2007

Transient pressure data are often collected at various points in the wellbore, including the wellhead, for test interpretation. When data gathering takes place at a point other than the midpoint of producing (MPP) interval, either inadvertently or by design, serious interpretation problems may arise because of wellbore thermal effects. Many field tests conducted on gas, oil, and water injection wells show the severity of this wellbore-induced problem. This paper explores the consequences of thermal effects upon test analysis in some cases and presents new insights into both data collection and their interpretation. Existing methods do not capture the borehole physics to allow us to study this problem.

We present interesting synthetic and field cases. One field example shows that pressure actually can decrease during buildup tests in a gas well in a high-transmissivity reservoir. In this test, data were collected about 1,200 ft above the MPP in a 9,000-ft well because of mechanical restrictions downhole. We reproduced this observed behavior with the simulator. Pressure decrease in a buildup is caused by the dominating influence of thermal diffusion over pressure diffusion in a high-transmissivity system when measurements are made away from the MPP For the same reason, pressure increases during a drawdown test. Equally important, results of the computation show that even if data were collected at the MPP, the gauge's ability to resolve small changes in pressure would have been tested severely.
Reservoir Modeling and Simulation of a Middle Eastern Carbonate Reservoir
Authors: Sibley M. J. , Bent J. V. , Davis D. W.
Published: December 2007

A giant Middle Eastern reservoir was modeled and history matched during reservoir simulation. The model was used to help predict reservoir performance under various scenarios and to evaluate the impact on production rates, ultimate recovery, and economics. Implementation of an infill, extension, and pressure-maintenance plan is in progress. This model overcame shortcomings of previous models of this reservoir through detailed integration of geologic, geophysical, and engineering data. Among the data incorporated were slabbed core, thin-sections, core analyses, seismic, isotope, open-hole logs, thermal-decay-time (TDT) logs, repeat formation tests (RFT's), field-pressure surveys, oil and water production data, and production tests. Significant modifications were made to internal and external reservoir architecture, and a diagenetic barrier (DB) was discovered that is the primary barrier to aquifer support. Results of the study include increased booked reserves and production rates, additional infill wells, two reservoir extension area discoveries, and the design and implementation of a pressure-maintenance program.
Multiphase-Pump Field Trials Demonstrate Practical Applications for the Technology
Authors: Dal Porto D. F. , Larson L. A.
Published: December 2007

This paper presents the results of two multiphase-pump field trials. One field trial was conducted offshore on a platform in the Gulf of Mexico (GOM). It is a low-pressure boost (100 psi) application involving gas-lifted wells. The other field trial was conducted onshore in an oil field in Alberta, Canada. This multiphase pump was designed for a high-pressure boost (850 psi) capability with primarily rod-pumped wells feeding the suction of the pump.

The offshore pump was sized to handle the flow from one well. By lowering the back pressure on the well, increased production was realized. The increased flow from one of the wells far surpassed the predicted quantity. Early problems with the double mechanical seal system were overcome and a new, simplified single mechanical seal system has been designed and installed.

The onshore multiphase pump clearly demonstrated that a twin-screw pump can operate reliably in a field environment, even under severe slug flow conditions. The trial indicated that a considerable portion of the liquid in the recycle stream (required because of the high gas fraction of the multiphase fluid from the field) flashes into gas, which occupies more volume in the pump than if it remained liquid. This decreased the capability of the pump to handle net flow from the field. These conditions motivated a re-evaluation of the pump-sizing techniques.

Performance data and lessons learned information are presented for both field trials.
Bridging Adsorption of Flexible Polymers in Low-Permeability Porous Media
Authors: Zitha P. L. J. , Botermans C. W.
Published: December 2007

Polymers used in water control are believed to always invade low-permeability layers to a sizable extent, impairing oil production. For this reason, water-shutoff treatments are usually combined with zone isolation; however, zone isolation is impractical in most wells, and the polymer must be injected through the whole open interval. Small invasion of low-permeability layers must then be ensured by some intrinsic property of the polymer. This idea was proved in a recent study, where polymer penetration in low-to-medium permeability cores was shown to be much smaller than usually predicted. This effect was explained by the bridging adsorption of stretched chains across the smallest pores. This paper develops a mathematical model for this phenomenon, and checks its true effect on placement by use of a prototype reservoir. The simulations confirm that polymer penetration in low-permeability layers decreases greatly when bridging adsorption is present.
A 3D Field-Scale Streamline-Based Reservoir Simulator
Authors: Batycky R. P. , Blunt M. J. , Thiele M. R.
Published: December 2007

We present a new streamline-based simulator applicable to field scale flow. The method is three dimensional (3D) and accounts for changing well conditions that result from infill drilling and well conversions, heterogeneity, mobility effects, and gravity effects. The key feature of the simulator is that fluid transport occurs on a streamline grid rather than between the discrete gridblocks on which the pressure field is solved. The streamline grid dynamically changes as the mobility field and boundary conditions dictate. A general numerical solver moves the fluids forward in space and time along each streamline. Multiphase gravity effects are accounted for by an operator-splitting technique that also requires a numerical solver. Because fluid transport is decoupled from the underlying grid, the method is computationally efficient and very large time-steps can be taken without loss in solution accuracy.

We present results of the streamline-based simulator applied to tracer, waterflooding, and first-contact miscible (FCM) displacements in two and three dimensions. Where possible, comparisons with conventional methods indicate that the streamline model minimizes numerical diffusion and is up to two orders of magnitude faster. We also demonstrate the efficiency of the method on a field-scale, million-gridblock, 36-well waterflood that includes a pattern-modification plan to improve oil recovery. Last, we present results of the method applied to the House Mountain waterflood in Canada.
Pressure and Composition Effect on Wax Precipitation: Experimental Data and Model Results
Authors: Pan Huanquan , Firoozabadi Abbas , Fotland Per
Published: December 2007

Wax precipitation is often studied using stock-tank oil. However, precipitation may be very different in well-tubing and production facilities because of the effects of pressure and composition. For example, the cloudpoint temperature may decrease as much as 15 K from atmospheric pressure to a saturation pressure of 100 bar mostly because of the solubility of light hydrocarbons into the oil (i.e. because of composition effect).

In this study, the cloudpoint temperature (CPT) at live-oil conditions and the amount of the precipitated wax at stock-tank-oil conditions are provided for four crudes. For one of the crudes, the effect of dilution with C1, C3, n-C5, n-C7, n-C10, n-C12, and n-C15 on the CPT is measured. A modified multisolid-wax model is used to study the effects of pressure and composition on wax precipitation. The experimental data and model results reveal that the CPT rises with the increase of the pressure and decreases when a crude is mixed with light hydrocarbons (such as C1, n-C5, and n-C7).
Pilot Tests of Alkaline/Surfactant/Polymer Flooding in Daqing Oil Field
Authors: Wang Demin , Zhang Zhenhua , Cheng Jiecheng , Yang Jingchun , Gao Shutang , Li Lin
Published: December 2007

After the success of polymer flooding in Daqing, two alkaline/surfactant/polymer (ASP) floods were conducted to increase oil recovery further, to study the feasibility of ASP flooding, and to provide technical and practical experience for expanding the ASP pilots. The crude oil of both pilots has a high paraffin content and low acid value. After extensive screening, an ASP system with very low surfactant concentration and wide range of ultralow interfacial tension (IFT) with any concentration change of the three components was determined for each pilot. Coreflooding and numerical simulation show more than 20% original-oil-in-place (OOIP) incremental recovery by ASP over waterflooding for both pilots. The ASP flood pilot tests are technically successful and, on the basis of preliminary evaluation, economically feasible; therefore, much larger-scale ASP-flooding field tests are planned in Daqing oil field in the near future.
Development of a Low-Cost FPSO for Service in the Zaafarana Oil Field, Egypt
Authors: McCarthy Tomás
Published: December 2007

This paper presents an overview of the Zaafarana oil field development and a more detailed account of the conversion of its floating production, storage, and offloading facility (FPSO), concentrating on the contractual and cost elements of that work.

The development presented a series of unique challenges and set a number of firsts. These included the redeployment of an internal turret mooring system, use of a turret-based electrical-cable jumper system, and the permanent use of cable-deployed electric submersible pumps in the gravel-pack well completions.

The Zaafarana FPSO was delivered with change order work amounting to less than 3% of the contracted price and within 10 days of schedule (adjusted for permitted delays). Award of contract to first oil was 1 year. This was achieved through the adoption of a low-cost approach, concentrating on obtaining only essentials, with a minimum of preferential engineering. Flexibility of approach to problem solving and maintenance of a nonconfrontational attitude between contracting parties proved essential.
Field Experiences and Guidelines for Use of Nonviscous Fluids in Frac-Pack Operations
Authors: Capra Laura , Ripa Giuseppe , Ferrara Giovanni , Travis Robin
Published: December 2007

In the Adriatic offshore area, conventional cased-hole gravel-pack completions have generally produced low flow efficiences (10 to 50%) from the multilayered reservoirs of low-to-medium gas permeability (1 to 50 md). This has been attributed to the poor communication between the wellbore and the producing layers, caused by limited exposure of the interval and poor filling of the perforation tunnels with gravel. This is confirmed by openhole gravel-pack (OHGP) completions where much higher flow efficiencies are observed.

The frac-pack technique, which combines gravel-pack and fracturing technologies, can improve communication between the layers in perforated completions by creating a vertical fracture with high conductivity and the injectivity necessary to fill the perforation tunnels. In addition, any existing near wellbore damage will be bypassed.

This paper reviews the field experience gained from over 80 frac-pack operations that have been performed during the last 2 years in the thin, interbedded layers of poorly consolidated sand and shale commonly found in the Adriatic area. Owing to their relatively low permeability, these formations can be fractured with nonviscosified fluids at pump rates less than 1 bbl/min. Consequently, completion brine was selected as the treating fluid. To reduce operational time and costs, the frac-pack treatments were carried out with the gravel-pack assembly in place and injection rates of up to 7 bbl/min were used with gravel concentrations staged from 1 to 4 lbm/gal. Fluid losses were encountered after the frac-pack treatments and were controlled by spotting a small pill of drill-in fluid (containing calcium carbonate) that was sized to bridge inside the screens. This paper presents the production performance of the frac-pack completions and establishes guidelines for future applications of frac-pack operations in similar reservoirs.
Amphoteric Polymer Improves Hydrocarbon/Water Ratios in Producing Wells—An Indonesian Case Study
Authors: Stanley F. O. , Tanggu P. S. , Hardianto _ , Marnoch Ewen
Published: December 2007

Exorbitant water production is constantly burdening the oil industry, especially as lifting and facility costs rise and disposal of produced water becomes increasingly expensive and environmentally sensitive. An amphoteric polymer material (APM), previously described in Ref. 2, has been successfully applied in Indonesia. This product reduces water cut and very often increases hydrocarbon production by effectively reducing the permeability to water without significantly changing the formation permeability to hydrocarbons. This paper reviews the mechanism, application, and associated laboratory results by which the APM polymer reduces water cut, with a primary emphasis on Indonesian case histories.

The product can successfully and economically reduce water production, often with the added benefit of increased hydrocarbon production. Results also indicate that high-permeability sandstone reservoirs with water-production problems can benefit from APM treatments. Laboratory and field results show good product application under high-shear situations and at temperatures up to 275°F.1,2,4 Careful candidate selection and good placement techniques, in conjunction with production logging to determine water location, are important to the success of APM jobs.
The Mustique/Shasta Project: A Small Operator's Deepwater Management Challenge
Authors: Huber D. S. , Smith C. D.
Published: December 2007

The project-management approach taken by a small independent oil company's first venture into subsea is described from initial business plan scoping economics to putting the wells on-stream. Hardy Oil & Gas U.S.A. Inc. (now Mariner Energy Inc.) wanted to remain strictly a producer without a large internal engineering staff. However, they were averse to delegating the project management or design responsibility to an outside company. The solution was a project-management-team approach with senior representatives of the major vendors being directly involved in the upfront design process. The vendor-selection process included all the major contracting methods including turnkey, partnering, teaming, and cost plus.

The Mustique/Shasta project in the Gulf of Mexico included three wells in 800- to 1,100-ft water depth tied back 9 to 12 miles to two platforms in 650-ft water depth.
Mechanisms of Wetting Alteration by Crude Oils
Authors: Buckley J. S. , Liu Y. , Monsterleet S.
Published: December 2007

Polar crude oil components can adsorb on mineral surfaces and alter their wetting properties. Extrapolating from laboratory observations of wetting alteration to reservoir conditions is difficult because of the chemical complexity of the crude oils, the variability of mineral surfaces, and the presence of brine. It is essential to recognize that the polar components of crude oils can adsorb by several distinct mechanisms, depending on factors that include brine composition and the solvent quality of the oil for its asphaltenes. In this article, several important mechanisms are identified. These have been demonstrated by experimental observations of contact angles between pure fluids on flat surfaces after exposure to crude oil. The consequences of these mechanisms for wetting alteration by different crude oils in porous media are examined.
Further Investigations of Why Gels Reduce Water Permeability More Than Oil Permeability
Authors: Liang Jenn-Tai , Seright R. S.
Published: December 2007

In this paper, we investigate why some gels can reduce the permeability to water much more than to oil. This property is critical to the success of chemical-based water-shutoff treatments in production wells if hydrocarbon-productive zones cannot be protected during placement. We first briefly review previous findings and the validity of several possible explanations for this disproportionate permeability reduction. Next, we describe experiments that test the validity of a promising mechanism—the segregated pathway theory. This theory speculates that on a microscopic scale, aqueous gelants follow water pathways more than oil pathways. Our experimental results in cores support this mechanism for oil-based gels, but not for water-based gels. We also explore another interesting mechanism that involves a balance between capillary and elastic forces. Results from our experiments support this mechanism for flow in tubes and micromodels, but not in porous rock. Other mechanisms are also discussed.
Operating Electrical Submersible Pumps Below the Perforations
Authors: Wilson B. L. , Mack John , Foster Danny
Published: December 2007

The electrical submersible pump (ESP) uses the flow of well fluid to cool the motor. This, traditionally, has been done by landing the ESP above the perforations or by using a shroud to redirect the fluid around the motor. This paper examines some of the advantages and disadvantages of ESP operation below the perforation. Several equipment options necessary for this type of operation are presented, along with an operator's field experience where below-perforation operation looked to be advantageous.
Application of Seismic Monitoring To Manage an Early-Stage Steamflood
Authors: Waite M. W. , Sigit Rusdinadar , Rusdibiyo A. V. , Susanto Toni , Primadi Hari , Satriana Denny
Published: December 2007

Time-lapse seismic monitoring technology has recently been introduced to the Duri field reservoir-management process as a means of directly imaging changes in vertical and horizontal steam distribution over time. The technique consists of repeated acquisition of three-dimensional (3D) seismic surveys to measure steamflood-induced changes in the acoustic properties of hydrocarbon reservoirs. The resulting seismic images are processed, parameterized, and translated to relevant engineering parameters. In this case study, steam flow was monitored during the early stages of steam injection by mapping anomalous seismic-reflectivity response within the steam-flow layers. Seismic-reflectivity data and borehole information were combined by use of multivariate statistical analysis and image processing techniques to produce images of steamflood conformance at the flow-unit level. The images reveal important insights into steam-flow behavior and were used to design a conformance-improvement program for the case study focus area.
Well Design Using a Computer Model
Authors: Helmy Mohamed Wael , Khalaf Fouad , Darwish T. A.
Published: December 2007

In this study, the theory of nonlinear optimization is used to develop a well-design computer model to determine the optimum directional parameters to minimize drilling depth and reduce drilling costs. The model uses the sequential unconstrained minimization technique (SUMT) to minimize drilling-depth objective function. Also, the model is used to calculate well surveys, simulate bit walk, and determine optimum lead angle to kick a well off. The minimum drilling depth is achieved at the minimum values for kickoff point, inclination, and angle-buildup and -dropoff rates. These minimum parameters reduce the dogleg severity, which, in turn, reduces the chances for operational problems like high torque and drag. The computer model has been validated by comparing a conventional design and an optimized design for a well drilled in the Gulf of Suez. The optimization model produced less drilling depth and lower inclination and dogleg severity.
Methodology for Numerical Simulation With Cycle-Dependent Relative Permeabilities
Authors: Larsen J. A. , Skauge Arne
Published: December 2007

Multiphase flow involving saturation oscillations should be modeled with history-dependent, relative permeability functions. Earlier approaches have been based on two-phase flow. The main assumptions have been that the imbibition process is reversible. Moreover, scanning curves were developed only for saturations between some extreme values.

Several tertiary oil recovery processes have shown cycle-dependent hysteresis for relative permeability. When saturation oscillations occur during three-phase flow such as water alternating gas (WAG), the two-phase hysteresis models will generally not be able to describe relative permeabilities obtained from corefloods. For three-phase flow, local hysteresis effects may also be important. New relative permeability representations that account for local hysteresis effects are presented.

Hysteresis models for both wetting and nonwetting phase permeabilities have been developed. The new models account for reduced mobility and irreversible hysteresis loops during three-phase flow. The models depend on the initial saturation at the start of the given process. An algorithm is presented for implementing the nonwetting phase hysteresis model in a numerical simulator. The new three-phase models use experimental wetting and nonwetting relative permeabilities as input, and knowledge of relations between maximum nonwetting saturation and trapped nonwetting saturation.
Wellbore Two-Phase Flow and Heat Transfer During Transient Testing
Authors: Hasan A. R. , Kabir C. S. , Wang Xiaowei
Published: December 2007

This paper presents a comprehensive wellbore/reservoir simulator to study pressure-transient behavior during two-phase flow in a vertical or deviated wellbore. We adapted a hybrid approach by modeling the wellbore numerically in which mass, momentum, and energy of the fluids are conserved, while treating the reservoir fluid flow analytically. Conductive heat transport occurs through the tubulars, cement sheaths, and formation. Both conductive and convective heat transport mechanisms are operative for the annular fluid, however. For an offshore well, convective heat transfer through seawater and air are also considered.

The simulator can be run in two modes. In forward simulation, transient pressure and temperature can be computed at any point in the wellbore, given the reservoir and completion parameters. Conversely, in a reverse simulation, bottomhole pressures (BHP's) can be computed given the pressure and temperature measurements at any other point in the borehole, including at the wellhead. However, the quality of reverse simulation derived solution is likely to suffer with increasing gas/oil ratio (GOR). Field data were used to show both features of the simulator.

Computational results show that the effect of heat loss through seawater is marginal for most offshore wells with a short submerged section (<500 ft) because of the fluids’ short residence time. However, for wells with long submerged tubulars (>2,000 ft), heat loss to the seawater becomes significant. Similarly, a deviated well loses more heat to the formation than its vertical counterpart because of increased residence time. Among major variables, thermal conductivity of the annular fluid plays a key role in heat retention and, therefore, in the wellhead temperature (WHT).
Two-Phase Zero-Net Liquid Flow in Upward Inclined Pipes: Experiment and Modeling
Authors: Amaravadi Sridhar , Minami Kazuioshi , Shoham Ovadia
Published: December 2007

The effect of pressure on two-phase zero-net liquid flow (ZNLF) in upward inclined pipes has been studied experimentally and theoretically. Experimental data were acquired for four upward inclination angles, namely, 1,2, 5, and 9°, and for three system pressures of 14.7, 44.7, and 64.7 psia. A sequence of flow configuration was observed with increasing gas flow rate as follows: slug flow for low superficial gas velocities; protoslug for medium velocities; and pulsating, small-amplitude waves or roll waves at high velocities. At a particular velocity of gas, termed the blowout velocity, all the liquid was blown out of the pipe. An analysis of equilibrium stratified flow, at the limit of very low and zero liquid flow rates, has been carried out. It was found that, under these conditions, the flow is always unstable, resulting in intermittent or pulsating stratified flow. A model has been developed for the prediction of the blowout velocity, as well as average liquid holdup and pressure gradient under ZNLF conditions. A very good agreement was observed between the predictions of the proposed model and the experimental data.
The Triangle "U" Sussex Unit—A Case History Comparing Two Chemical Enhanced Waterflood Methods
Authors: Smith J. E. , Larsen Dan
Published: December 2007

The Triangle "U" unit is located in Campbell County, Wyoming, in the Powder River basin. The field produces mainly from the Sussex A sandstone, with completions and limited production from the Sussex B. The flood recovered 12.8% original oil in place (OOIP) on primary before the waterflood, which began in March 1981. The Sussex A is relatively tight, with an average permeability of 15 md and porosity of 13.5%. The rock contains swelling and migrating clays, and the initial injection water source was fresh, leading to concerns about long-term injectivity. To stabilize clays, two different processes were applied. Earlier injection wells were treated with a combination of potassium chloride (KCl) and cationic polymer. Later injection wells were treated with potassium hydroxide (KOH). A recent comparison of long-term performance of the two groups of injection wells shows that the wells treated with KOH injected 476,437 bbls/porosity-ft more water than the wells treated with cationic polymer, in 1.4 years less time. This is an 83% increase in cumulative water injection. After KOH, all injection wells were put on a low concentration of imbibition agent to maximize in-depth penetration of water into low permeable rock. Cumulative oil recovery through March 1997 is 36.4% OOIP, compared to the original waterflood projection of 26.6% OOIP. A total of 37.7% pore volume (PV) water has been injected, and the water/oil ratio (WOR) is currently 0.71, for a fairly efficient flood in this tight, dirty sandstone.
Thermal and Mechanical Considerations for Design of Insulated Tubing
Authors: Pattillo P. D. , Bellarby J. E. , Ross G. R. , Gosch S. W. , McLaren G. D.
Published: December 2007

Of the several options for controlling temperature in a well, vacuum-insulated tubing (VIT) has proven useful in a number of applications. Use of VIT, however, necessitates unique design considerations, from both a thermal and mechanical perspective.

This paper describes the application of VIT for a particular purpose—to minimize temperature change, and associated annular fluid-expansion pressures, in a deepwater well design. The specific application, however, lends background to more general design considerations associated with VIT. Thermally, the importance of heat loss at the couplings to the overall design is discussed, using both numerical analysis and experimental results previously reported in the redesign of wells for the Marlin tension-leg platform (TLP). Mechanically, a detailed examination of the loads to which VIT may be subjected also uncovers special considerations.
Measurements and CFD Modeling of Drag-Reduction Effects
Authors: Koskinen Jukka , Manninen Mikko , Pättikangas Timo , Alopaeus Ville , Keskinen Kari I. , Kolehmainen Eero
Published: December 2007

Computational-fluid-dynamics (CFD) modeling of drag reduction (DR) by polymer additives dissolved in hydrocarbon was carried out in pipe flows and in a rotating shear viscometer. A two-layer turbulence model was applied that described turbulence damping by the molecules of drag-reducing additives (DRAs) in the near-wall regions. The von Karman constant in the near-wall region was used as the model parameter. Extensive measurements of the DR effect for a rotating viscometer were performed at different Reynolds numbers, apparent molar masses, and DRA concentrations. The model with only one fit parameter was able to reproduce the experimental results in both pipe flows and the rotating viscometer. Experimental results were used in relating the model parameter to the relevant physical properties.
High-Power/High-Frequency Acoustic Stimulation: A Novel and Effective Wellbore Stimulation Technology
Authors: Wong Sau-Wai , van der Bas Fred , Zuiderwijk Pedro , Birchak Bob , Han Wei , Yoo Kwang , van Batenburg Diederik
Published: December 2007

Local impairment of formation permeability often causes reduced production because of the interaction of the reservoir with drilling and completion fluids. The problem may be further compounded by impairment caused by fines migration during production.

High-frequency sonic and ultrasonic waves have been used in many industrial applications to remove contaminants, such as dirt, oil, and grease from parts that are immersed in fluids. An obvious extension of this application is the removal of wellbore impairment by exposing it to high-frequency acoustic waves. The influence of high-frequency waves is limited to the near-wellbore environment because of high attenuation. Dedicated experiments under realistic downhole conditions have been carried out in both linear and radial configurations. We have examined the acoustic power needed to remove near-wellbore formation damage caused by fines and particles plugging pores as well as drilling-induced damage. Specific issues related to well completion and the envelope of acoustic stimulation are presented. The laboratory results have led to the design and construction of a slim, high-power, and high-frequency (above 10 kHz) downhole acoustic tool for field deployment.

This paper outlines the concept and presents key experimental results to support the claim. Key features of a prototype downhole tool are also described.
A Streamline-Based Method for Assisted History Matching Applied to an Arabian Gulf Field
Authors: Agarwal Bijan , Blunt Martin J.
Published: December 2007

A streamline-based history-matching method is presented that overcomes two of the major limitations of previous approaches: (1) it uses a three-phase compressible streamline simulator for the forward simulation, and so its application is not limited to incompressible waterfloods; and (2) geological constraints, such as regions of differing facies, can be honored. Permeability, porosity, and anisotropy can all be modified using the methodology of Assisted History Matching.1–3 In this paper, the technique is extended with suggested modifications to the reservoir description computed assuming tracer-like flow. This allows the engineer to direct the parameter changes through interactive code.

The method is applied to history matching the full-field model for the Southwest Fateh Mishrif field located in an offshore concession in the Emirate of Dubai. The Southwest Fateh Mishrif is a carbonate reservoir containing a highly undersaturated oil. There are currently 42 active producers and 27 active water injectors. First production occurred in 1972, and waterflooding commenced in 1975 prior to the field average reservoir pressure falling below the bubblepoint, with present injection rates of 320,000 BWPD.
Critical and Sub-critical Oil/Gas/Water Mass Flow Rate Experiments and Predictions For Chokes
Authors: Schüller R. B. , Munaweera S. , Selmer-Olsen S. , Solbakken T.
Published: December 2007

A large database on critical and subcritical flow through orifice-and cage-type chokes have been obtained in the Multiphase Flow Loop (MPFL) of Norsk Hydro Oil and Gas R&D Center in Porsgrunn, Norway. This work is an extension of the studies performed in 1999 (367 data points) by Schüller et al. (2003), making a total data set of 509 data points. The downstream separator pressure and temperature were kept at 8 bara and 50°C, respectively. The maximum upstream pressures were approximately 40 bara, giving a maximum pressure ratio of approximately 4.

The Hydro models (Schüller et al. 2003) show a very good agreement for prediction of mass flow rate, both for critical and subcritical flow conditions, with an average error of absolute values of 6.2% and a standard deviation of 8.9%. Comparisons with the models of Sachdeva et al. (1986) and Perkins (1993) show that the performances of these models are not as good as the Hydro model. The Sachdeva model and the Perkins model both have average errors greater than 22%, with standard deviations greater than 25%.

The Hydro models also seem to predict reasonably correctly the transition between subcritical and critical flow conditions.
Water Shutoff in Gas Wells: Proper Gel Placement Is the Key to Success
Authors: Wassmuth F. R. , Green K. , Hodgins L.
Published: December 2007

The objectives of water-shutoff treatments in gas wells suffering from water influx are to reduce water production and, at the same time, increase gas-production rates and producible gas reserves. Several field treatments, conducted under the umbrella of a research project focused on water abatement in gas wells, have demonstrated that a sequential gel/gas-injection technique in fractured gas reservoirs was successful in reducing water production and increasing gas production. Further efforts focused on improving gel placement in both fractured and matrix reservoirs to improve the treatment efficiency.

Injectivity of the gelant was improved for injection into matrix reservoirs by either reducing the concentration of the highmolecular-weight polymer in the gelant formulation or by using a low-molecular-weight polymer.

Gel placement was improved by displacing the gelant away from the near-wellbore region with semistable foam rather than with gas. Such displacement allows for improved gas production after the gel treatment.

Laboratory-scale simulations were used to history match the coreflood results to calibrate the gelation and overdisplacement options in the simulations.

Field-scale simulations demonstrated the merits of the proper gel-placement technique using a foam to displace the gelant away from the wellbore in matrix and fractured reservoirs.

Optimized gel formulations in combination with the new over-displacement technique provide a treatment alternative for combatting 3D coning situations. This overdisplacement technique can also minimize the startup problems experienced in fractured gas reservoirs after gel treatments.
A Modified Spinning Drop Method for High-Temperature Applications
Authors: Handy L. L. , El-Gassier M. , Ershaghi I.
Published: December 2007

A constant-speed (3,600-rpm) spinning drop apparatus1 has been modified to measure interfacial tensions (IFT's) at elevated temperatures and pressures. The modification includes the addition of a temperature air bath and the development of a method to seal the fluids in the capillary tube. The modification described here is a very inexpensive and practical method that extends the application of the spinning drop to 302°F (150°C). This allows studies on the IFT properties of surfactant oil systems in high-temperature applications such as the use of additives in thermal recovery.

The air bath is made of a ¾-in. (1.9-cm) thick Marinite mix (an asbestos-free insulation) with a temperature rating as high as 600°C (1100°F). Uniform temperatures are maintained with flow mixing vanes. Temperature measurements are made with J-type thermocouples placed next to the capillary tubes. A schematic of the equipment is shown in Fig. 1.

The open ends of the capillary tubes are sealed with a high-temperature epoxy (Fig. 2). The epoxy used is Dexter Corp. product No. 9340. It hardens quickly and is capable of withstanding pressures up to 855.7 psi (5.9 MPa). The epoxy seal easily can be drilled out to permit the reuse of the tubes. During the placement of the fluids and the epoxy resin, an air gap is retained for thermal expansion of the fluids. The air gap also prevents direct contact between the fluids and the resin.
The Key to Predicting Emulsion Stability: Solid Content
Authors: Poindexter Michael K. , Chuai Shaokun , Marble Robert A. , Marsh Samuel C.
Published: December 2007

Chemical demulsifiers are routinely added in the oil field to effectively resolve water-in-crude-oil emulsions. As used in the common bottle test, demulsifiers, in effect, probe or interrogate emulsion stability strength. Emulsion stability, in turn, is defined by no fewer than three parameters: water drop, oil dryness, and interface quality. All three parameters are direct outputs of the bottle test, and, collectively, all three provide a more complete picture of emulsion stability, as opposed to the use of any singular parameter.

By selecting a wide variety of demulsifiers and by performing a standardized bottle test, emulsion stability from a variety of sites can be quantified and compared. By coupling bottle test results with corresponding crude oil analytical data, fundamental questions concerning factors governing emulsion stability can be quantified. The results show that solid content, not asphaltene content or any other crude oil parameter investigated, is by far the best single predictor for gauging emulsion stability. Furthermore, statistical analysis through partition trees shows that emulsion stability is most aptly described using several crude oil parameters, as opposed to one single factor.
Pickling Well Tubulars Using Coiled Tubing: Mathematical Modeling and Field Application
Authors: Al-Mutairi S. H. , Hill A. D. , Nasr-El-Din H. A.
Published: December 2007

Coiled tubing is usually used to conduct acid pickle treatments. The purpose of the treatment is to prevent pumping damaging materials into the formation before the main acid job. In this case, the acid is pumped down the coiled tubing, and then flowed up through the tubing-coiled tubing annulus. Pickling is a process of flow with heterogeneous reactions occurring with mill scale (Fe3O4) and other contaminants at both the inner wall of the production tubing and the outer surface of the coiled tubing.

Pickling is an essential part of well stimulation treatments if the main treatment fluids (e.g., acidizing, fracturing, and gravel packing) if the main treatment fluids are to be bullheaded. However, it appears that traditional pickle practices are overestimating the required acid volume and/or concentration. Field data indicate that excessive acid volumes are used for tubing pickle because large returns of unreacted acid are usually recovered on the surface.

In this paper, mechanisms to explain the behavior of acid contact with the tubing are presented, and a model for predicting acid consumption and dissolution of tubular contaminants is developed. The model includes reactions of acid with mill scale. A system of nonlinear, partial differential equations is developed, and the equations are solved numerically to predict the concentrations of major species as a function of axial position along the tubing and in the effluent from the well during flowback.

Field application included pickling of low-carbon steel tubing (11,900 ft of 5.5-in. C-95) using coiled tubing. A slug of 5,000 gals of 20 wt% HCl with additives was used. Samples were collected from the treated well during the flowback of the pickling treatment. The model was used to predict the concentrations of various species in the well flowback samples. Model predictions for acid, chloride ion, and total iron concentrations were in agreement with field results. In addition, the model proved to be a valuable tool in optimizing future pickling treatments.
Downhole Pressure Boosting in Natural Gas Wells: Well Candidate Selection and Project Progress
Authors: Liley J. E. N. , Oakley S. D.
Published: December 2007

In recent years, gas exploration and production (E&P) companies have acknowledged that pressure boosting in close proximity to a reservoir can accelerate production rates as well as increase the recovery of reserves beyond that possible by conventional central compression alone. This paper summarizes the key well and reservoir parameters that determine the production enhancement potential of downhole gas compression (DGC).

An industry-funded joint industry project (JIP) has been established to complete the development of this key enabling technology. Detailed design is well under way, with the objective of completing a field trial in 2007. A summary of progress to date on this project is included in this paper.
New Frac-Pack Redesign Methodology Improves Estimation of Tip Screenout Post-FET
Authors: Edwards W. J. , Gauthier S. , Clarkson B.
Published: December 2007

When the first frac pack was performed in the Gulf of Mexico (GOM) over a decade ago, very little was known about the effects this form of sand control would have on the intended formation. Even less was known about how to optimize the treatment to obtain the most benefit for the formation. Since that time, the sand control community has learned a great deal about the effects and benefits of frac-packing various unconsolidated formations throughout the world. However, most of the knowledge and design criteria have remained housed within the minds of individuals and cannot be looked at as a whole to find trends and fine-tune the design methods currently being used. Another complicating factor is the number of frac models of varying degrees of complexity being used within the industry. Therefore, even though thousands of frac packs have been performed globally, frac-pack redesign methods are still subjective and differ from individual to individual and from model to model.

The recent creation of a database that houses selected formation evaluation test (FET) and frac data along with model-specific parameters allows full-scale analysis of a large number of jobs pumped in the Gulf of Mexico (GOM). With a consistent analysis procedure in place, the database, populated with numerous treatments by engineers working throughout the GOM, can be analyzed objectively. The data contained in this database include rock mechanics, net pressures, pumping trend data, tip screenout (TSO) times, and other variables.

This paper explains the methodology and discusses the results of the database analysis, using case studies to determine the best method for analysis of the jobs. Crossplots show the correlation between TSO prediction and actual events and suggest recommendations for more successful design work in the future. This paper is meant to give up-to-date guidelines for designing better frac packs.
Rigless Interventions in Failed Gravel-Pack Gas Wells Using New Resin Systems
Authors: Lightford S. C. , Pitoni E. , Emiliani C. N. , Devia F. , Valli V.
Published: December 2007

When a gravel-pack completion fails, it usually results in loss of production for the interval until a workover rig is available to recomplete the well. This paper describes two recent successful rigless interventions completed in offshore multizone completed gas wells in the Adriatic Sea. A key factor in the success of these remedial treatments has been the application of two different chemical technologies applied to the proppant while it is being pumped into the well.

In the first well, production loss was caused by fines migration (fine silt ≤44 microns) into the 40/60 gravel-pack sand, which completely plugged the screens and gravel. An intervention was performed which included sealing the existing completion and then reperforating the premium screen using wireline guns. The interval was then fractured with a tip screenout design and a through-tubing screen was placed across the perforated screen. Critical to this treatment was the use of a surface modifying agent to prevent fines migration and plugging of the gravel pack. Production results have confirmed the correctness of this technical choice.

A different problem existed with the second well, which had a frac-pack completion; in this case, a screen failure resulted in formation sand and proppant being produced to the surface. The well was refractured through the hole in the screen and a newly developed resin was applied to the proppant to lock the proppant into place and thus repair the damaged screen without restricting the flow area with a secondary inner string. Unlike conventional resin-coated proppant at low temperatures, this new type of resin does not require confinement pressure and/or the use of chemical flushes to cause the resin to set. Since the intervention, the well has been producing sand-free at very close to the original productivity index (PI).

In both cases, these treatments have put back into production wells that in the past could not have been restored to production except through recompletion using a workover rig. This paper will describe the treatment design, well operations performed, materials used, and production performance of each well, comparing each aspect with the case of a conventional recompleted well.
Solar-thermic sewage sludge treatment in extreme alpine environments
Authors: Becker W. , Schoen M.A. , Wett B.
Published: December 2007

In the framework of a program for environmental protection conducted by the German mountaineers' club (DAV) problems emerging from residual solids accumulating in on-site wastewater treatment plants of mountain refuges were investigated. To handle these problems in an ecologically and economically reasonable way two devices for solar-supported treatment of sludge and bio-solids have been developed. These units support gravity-filtration and evaporation of liquid sludge as well as thermal acceleration of composting processes. Two solar sludge dryers were installed and operated without external energy supply at alpine refuges treating primary and secondary sludge, respectively. Batch-filling during the season could increase load capacity and a total solids concentration of up to 40% could be achieved before discharge at the beginning of the next season. The promising results from the solar sludge dryer encouraged for the development of a solar composter. The period of temperature levels suitable for composting biosolids in mountain areas can be extended considerably by application of this technology – measured temperature distribution indicated no freezing at all.