bluuebunny/crossref_metadata_2025 huggingface dataset:
Experimental Investigation of Foamy Oil Flow Using a High Pressure Etched Glass Micromodel
Authors: Bora Rupam , Chakma Amit , Maini Brij B.
Published: December 2007

A series of flow visualization experiments were carried out using a high-pressure etched glass micromodel to gain insight into the pore level processes involved in foamy oil flow. The micromodel incorporated a realistic heterogeneous pore network with well-defined pore size distribution and pore throat size distribution. Solution gas drive experiments were conducted using a crude heavy-oil, a deasphalted fraction of the same crude oil, a synthetic mineral oil and a much lighter crude oil. The experimental results show that the rate of pressure drawdown was the most important parameter that altered the flow behaviour in the pore scale level and induced "foaminess" during the solution gas drive process. The dispersed gas flow occurred only in high rate tests and the dispersion was created by break-up of mobilized gas ganglia.

Mathematical expressions for nucleation rate were derived for various oil samples. A metering section at the downstream end of the micromodel was used to measure the volume of fluids expelled from the pore network. These volume measurements were used to estimate the total compressibility of the reservoir fluids before the formation of visible bubbles. The compressibility numbers were used to infer the presence or absence of micro-bubbles that would be too small to be seen but could contribute significantly to oil recovery. The estimated compressibility values suggest thatt some microbubbles were perhaps evolved during the depletion process. However, it appears that most of these microbubbles remained attached to the pore walls; only a handful became detached and grew into larger bubbles.
Experimental Study of Overburden and Stress Influence on Non-Darcy Gas Flow in Dakota Sandstone
Authors: Zeng Zhengwen , Grigg Reid , Ganda Sukesh
Published: December 2007

A series of laboratory experiments were conducted to investigate the influence of overburden and in-situ stresses on non-Darcy gas flow behavior in Dakota sandstone. Nitrogen was flooded through cylindrical core in a triaxial core holder under specific condition of temperature at 100°F, with core outlet pore pressure at 500 psi, axial and radial stress from 2.000 to 10,000 psi, and. nitrogen reservoir pump pressure at 2.000 psi with pump flow rates from 25 to 10,000 cc/hr at 80°F. Permeability and non-Darcy coefficient were determined using Forchheimer's method. It was found that with the increase of overburden and in-situ stresses, permeability decreases while non-Darcy flow coefficient increases. Average effective normal stress and shear stress were used to quantitatively express the influence of overburden and in-situ stresses. It was found that average effective normal stress has a good linear relationship with both permeability and non-Darcy flow coefficient. In contrast, average shear stress did not appear to influence the permeability and non-Darcy coefficient.
Streamline-based Production Data Integration Under Realistic Field Conditions: Experience in a Giant Middle-Eastern Reservoir
Authors: Qassab H. , Pavlas M. Khalifa R. , Afaleg N. , Ali H. , Kharghoria A. , He Z. , Lee S. H. , Datta-Gupta A.
Published: December 2007

In this paper we apply the streamline-based production data integration method to condition a multimillion cell geologic model to historical production response for a giant Saudi Arabian reservoir. The field has been under peripheral water injection with 16 injectors and 70 producers. There is also a strong aquifer influx into the field. A total of 30 years of production history with detailed rate, infill well and reperforation schedule were incorporated via multiple pressure updates during streamline simulation. Also, gravity and compressibility effects were included to account for water slumping and aquifer support. To our knowledge, this is the first and the largest such application of production data integration to geologic models accounting for realistic field conditions. We have developed novel techniques to analytically compute the sensitivities of the production response in the presence of gravity and changing field conditions. This makes our method extremely computationally efficient. For the field application, the production data integration is carried out in less than 6 hours in a PC.

The geologic model derived after conditioning to production response was validated using field surveillance data. In particular, the flood front movement, the aquifer encroachment and bypassed oil locations obtained from the geologic model was found to be consistent with field observations. Finally, an examination of the permeability changes during production data integration revealed that most of these changes were aligned along the facies distribution, particularly the ‘good’ facies distribution with no resulting loss in geologic realism.
Optimizing Helium Gas Recovery: A Compositional Dual Porosity Reservoir Simulation Study of the Bush Dome Helium Storage Reservoir, Amarillo, Texas
Authors: Weinstein Charles , Firincioglu Tuba , Albertoni Alejandro
Published: December 2007

This paper describes the process and results of the integrated field study for the Bush Dome reservoir in Amarillo, Texas, which is the world's only helium gas storage reservoir. Starting in 2003 the BLM is required by law to begin producing the stored helium in order to recover all of the helium reserves by 2015. The purpose of this study was to provide the BLM with a reservoir characterization that would have the predictive capability to optimally recover the stored helium within the restrictions imposed by the surface facilities and the requirements of the Helium Privatization Act of 1996. While optimizing the helium recovery prediction cases, innovative applications of the simulator features were implemented. The final optimization provided the BLM with production guidelines to meet the helium recovery objectives. The results not only provided a detailed production schedule, but also the information necessary to make appropriate decisions during the 13 year recovery period.
Turbulent Flow of Non-Newtonian Fluid in Coiled Tubing: Numerical Simulation and Experimental Verification
Authors: Zhou Y. , Shah S. N.
Published: December 2007

A comprehensive theoretical analysis of turbulent flow of a power law fluid in coiled tubing was conducted with the approach of boundary layer approximation. Equations of momentum integrals for the boundary layer flow were derived and solved numerically. Based on the results of the numerical analysis, a new friction factor correlation was developed which is applicable to a wide range of fluids used with coiled tubing operations. The new correlation was verified by comparing it with the published Ito correlation for the special case of Newtonian fluid. For non-Newtonian fluids, there is also a close agreement between the new correlation and the experimental data from recent full-scale experiments.
Evaluation of a Safe, Slightly Acidic Tubing Clean-Out Fluid
Authors: Berry Sandra L. , Boles Joel L. , Di Lullo Gino Francesco
Published: December 2007

Traditional "Best Practices" completion procedures recommend an acid pickle treatment to clean-out all tubulars in a wellbore prior to pumping an acid treatment or a "solids-free" completion brine system. The potential contaminants (iron oxidation, hydrocarbon deposits and pipe dope) can create formation damage if pumped into the formation during the main treatment. In addition, contamination of "solids-free" completion brine can lead to increased location diatomaceous earth (D.E.) filtration time.

Tubing clean-out treatments normally consist of a slug of acid (10 to 15wt% hydrochloric) being pumped inside the tubulars and then reverse circulated back to surface without fluids being lost to the formation. A solvent is typically added to assist in the removal of pipe dope and organic deposits. Inhibitor and a surfactant, to facilitate wetting, are the normal fluid additives. Handling and disposal of this fluid after clean up of the tubulars can be dangerous and very costly due to its corrosive nature (pH <0).

A slightly acidic (pH of 5.8-6.3) fluid has been evaluated in the laboratory for use as a pickling fluid to replace the traditional acids. This fluid's capability to remove iron scales on coiled tubing, prevent rust from reforming, clean up commercial pipe dopes and reduce corrosion rates, was compared to traditional hydrochloric acid. This fluid performed as efficiently as 15wt% hydrochloric acid in removing all potential contaminants associated with a workstring, while producing one fifth the corrosion rate. Furthermore, a work string treated with this fluid prior to being laid down on a pipe rack retained a protective coating that resisted re-oxidization for up to 30 days.
Optimization of Plunger-Lift Performance in Liquid Loading Gas Wells
Authors: Ozkan E. , Keefer B. , Miller M. G.
Published: December 2007

This paper presents an algorithm to optimize the production and shut-in periods of plunger-lift based on reservoir performance. The algorithm combines analytical models of reservoir and wellbore fluid flow. The implementation of the algorithm requires a relatively simple and inexpensive electronic control system. The new system may be connected to existing wellheads with minimal modification. One of the advantages of the new algorithm is the ability to automatically incorporate the changes in the line pressure. An example application is presented to indicate that the new algorithm may increase plunger-lift production by a factor of two.
Interpretation of Diagnostics-While-Drilling Data
Authors: Mansure A. J. , Finger J. T. , Knudsen S. D. , Wise J. L.
Published: December 2007

A number of dynamic drilling problems, such as whirl, chatter, and torsional oscillations require real-time downhole data if they are to be mitigated. Current measurement-while-drilling data transfer rates are too slow for these problems to be adequately addressed in a timely manner. Furthermore, data received at the surface must be displayed in real-time in an interpretable fashion if problems are to be recognized.

A Diagnostics-While-Drilling (DWD) system has been built and used in a series of proof-of-concept (POC) tests at the GTI Catoosa Test Facility. Test results demonstrate that real-time, high-speed, downhole drilling-dynamics data allow the recognition of, and reaction to, undesirable downhole conditions, thereby mitigating bit-damaging events that frequently occur but are unseen in surface data.

While the primary purpose of the system is to display information in real time, data are also archived for later analysis. For this reason, the system does not process data downhole. All data are transmitted to the surface. This requires a high-speed data link. The bandwidth available with mud pulse telemetry is several orders of magnitude too low for this application.

The volume and complexity of downhole information necessitates careful data-management techniques. Tests accomplished thus far with the DWD system have yielded many observations and lessons that pave the way for future improvements to the system and its function. These improvements promise to drastically reduce drilling-dynamics problems.
Effects of Mandrel, Borehole, and Invasion for Tilt-Coil Antennas
Authors: Hagiwara Terry , Banning Erik J. , Ostermeier Richard M. , Haugland S. Mark
Published: December 2007

Several recently published studies discuss the concept of inductive resistivity logging devices with oblique transmitting and/or receiving coils. Both wireline induction and LWD propagation resistivity tool concepts have been considered. Directional resistivity measurements and improved anisotropy measurements are among the benefits promised by this type of device. Analyses based on point-magnetic dipole antennas were used to illustrate these potential benefits. The effects of a metallic mandrel, borehole, and invasion were not considered due to the absence of a suitable forward model.

This paper characterizes mandrel, borehole, and invasion effects for a variety of candidate tilt-coil devices with antenna array parameters similar to those of the previous studies. The characterization is based on calculations from a new forward model that includes tilted transmitting and receiving coils of finite diameter embedded in a concentric cylindrical structure.

Important details of the forward model used in the calculations are also provided.
Innovative Concentric Reamer Enhances Deepwater Drilling Operations
Authors: Miller Gregory C. , Childers Ronald D.
Published: December 2007

A prevailing challenge in today's deepwater drilling arena is to have a reliable and cost-effective system able to simultaneously drill and enlarge a borehole for accommodating multiple casing string programs. This paper presents an innovative practice that advances hole enlargement capabilities and offers a cost-effective solution to wellbore enlargement in deepwater wellbores. The key component is the concentric reamer that is compatible with all rotary steerable and directional drilling systems. The design of this concentric reamer addresses known technical challenges and minimizes performance risks associated with using hole enlarging devices.

This paper profiles the development and testing, from concept to field-proofing, of a new tool for deepwater Gulf of Mexico applications in various lithologies and drilling scenarios.
CNG Transport Technology is Delivering on Promises
Authors: Dunlop John P. , White Charles N.
Published: December 2007

Natural gas supply shortfalls are forecasted for the next decade in the U.S. and certain other markets worldwide. Most ongoing efforts to address these shortfalls, such as LNG enhancements and the transition of GTL science from the laboratory to the field, require low gas prices and huge volumes to generate adequate economic returns, and thus have necessitated the targeting of large and remote sources.

The marine transport of compressed natural gas (CNG) represents a different approach to the delivery challenge, and recent breakthroughs in technology are providing CNG with the ability to cost effectively ship much larger volumes of gas over greater distances. Thus, CNG is expected to help economically access moderately sized resources (typically 1-5 Tcf) with greater scalability and flexibility while lowering overall capital requirements. Adding to CNG's attractiveness are the modest fixed infrastructure investments needed at the production and market delivery points, and a high degree of security through the use of offshore loading and offloading operations.
Wellbore Stability Challenges in the Deep Water, Gulf of Mexico: Case History Examples from the Pompano Field
Authors: Willson S. M. , Edwards S. , Heppard P. D. , Li X. , Coltrin G. , Chester D. K. , Harrison H. L. , Cocales B. W.
Published: December 2007

Several wellbore stability challenges are faced when drilling in deep water. Overburden sediments are typically weak and overpressured; pore-frac windows are therefore narrow; salt bodies may have to be penetrated; rubble zones may exist adjacent to the salt bodies; reservoir formations may be depleted, with consequent risks of lost circulation and differential sticking. Extended reach wells, required to access satellite reserves, require close monitoring of ECDs when drilling. The pore-frac drilling window may be further complicated by changes in water depth existing over the length of the well path being drilled.

All these challenges have arisen in the various wells drilled at BP's Pompano field in the deepwater Gulf of Mexico. This paper describes the wellbore stability challenges faced. Citing well case history examples, the paper describes the experiences gained in tackling these challenges through the pre-well analyses and post-well observations. The paper concludes by providing guidelines and recommendations for data collection, pre-planning activities, drilling practices and real-time ECD / wellbore stability management that should be implemented to eliminate non-productive time when drilling in these challenging environments.
Predicting and Preventing Wellbore Instability Using the Latest Drilling and Logging Technologies: Tullich Field Development, North Sea
Authors: Russell K. A. , Ayan C. , Hart N. J. , Rodriguez J. M. , Scholey H. , Sugden C. , Davidson J. K.
Published: December 2007

Innovative geomechanical, drilling, logging and seismic techniques have been used to successfully develop a geologically complex discovery in the North Sea, Tullich field. With individual reservoir unit thicknesses below the limit of seismic resolution, and a restricted depth window for completion, optimal placement of horizontal production wells, without delays, was vital to the successful and economical development of the field. Wellbore instability was a key concern after recent drilling experience in nearby fields with similar formations. By combining efficient teamwork and the latest technologies, the complex reservoir was successfully developed, both in terms of cost savings while developing the field, and good oil production.
The Role of Electrofacies, Lithofacies, and Hydraulic Flow Units in Permeability Predictions from Well Logs: A Comparative Analysis Using Classification Trees
Authors: Perez Hector H. , Datta-Gupta Akhil , Mishra S.
Published: December 2007

Predicting permeability from well logs typically involves classification of the well log response into relatively homogeneous subgroups based on either electrofacies, lithofacies or hydraulic flow units (HFU). The electrofacies-based classification involves identifying clusters in the well log response that reflect "similar" minerals and lithofacies within the logged interval. The procedure is straightforward and inexpensive. However, identification of lithofacies and HFU relies on core data analysis and can be expensive and time consuming. To date, no systematic study has been performed to investigate the relative merits of the three methods in terms of their ability to predict permeability in uncored wells.

The purpose of this paper is three-fold. First, we examine the link between the three approaches using a powerful and yet intuitive statistical tool called "classification tree analysis". The tree-based method is an exploratory technique that allows for a straight-forward determination of the relative importance of the well logs in identifying electrofacies, lithofacies and HFU. Second, we use the tree-based method to propose an approach to account for missing well logs during permeability predictions. This is a common problem encountered during field applications. Our approach follows directly from the hierarchical decision tree that visually and also quantitatively illustrates the relationship between the data groupings and the individual well log response. Finally, we demonstrate the power and utility of our approach via field applications involving permeability predictions in a highly complex carbonate reservoir, the Salt Creek Field Unit (SCFU) in West Texas. The intuitive and the visual nature of the tree-classifier approach also make it a powerful tool for communication between geologists and engineers.
Reliability Assurance, Managing The Growth Of Intelligent Completion Technology
Authors: Mathieson Derek , Rogers John , Rajagopalan Shashidhar , McManus Robert
Published: December 2007

Since the first Intelligent Completion in 1997 over 150 installations havebeen completed by the industry as a whole. Reliability assurance is recognizedas one of the central themes for continued market stabilization and growth inthis technology sector. A detailed review of actual field performance, drawingfrom a database of over 90 installations in various operating environmentsworldwide, is presented by generic system type in context with marketperception of risk associated with this technology. The paper focuses oninterpretation of the raw field data, primary analysis tools and how theinformation generated is being used to calibrate both reliability growthprograms for the technology and value optimization strategies for fielddevelopment.

Reliability trends are charted over the 5-year period from 1997, providing astatus check for both current and future expectations in system performance. Inaddition the paper describes the importance of both sub-system and architecturereliability and how these concepts, when calibrated with field performancedata, are being used to build realistic models for system reliabilityprediction and valuation risk analysis.
Voidage Replacement Ratio Calculations in Retrograde Condensate to Volatile Oil Reservoirs Undergoing EOR Processes
Authors: Clark Robert A. , Ludolph Brian
Published: December 2007

Voidage replacement ratio (VRR) is commonly used to measure the rate of change in reservoir energy. VRR optimization is often an important factor in planning and managing enhanced oil recovery (EOR) projects. VRR is easily calculated in black oil waterflooding operations. However, in reservoirs impacted significantly by compositional effects, calculation of VRR is nontrivial.

A reservoir that grades from retrograde condensate to volatile oil presents tremendous difficulties in determining VRR. The large vertical relief and associated steep compositional gradients commonly present in thrust belt regions further exacerbates this problem. An excellent example of this problem is the high-pressure miscible gas injection project in Boquerón Field (El Furrial Trend in Venezuela). At Boquerón, the saturation pressure varies with depth from 7,700 psia to 3,300 psia.

Typically, an equation of state (EOS) is constructed to model the phase behavior variability in compositional systems. In compartmentalized reservoirs, the initial composition can also vary areally. However, neither EOS programs nor typical compositional numerical models calculate and/or report VRR.

This paper presents a method (developed for Boquerón Field) to compute VRR for compositional systems using a compositional full field model (CFFM) and an EOS program. The field is broken up into major pressure compartments in the model. Regional compositions, pressures, injection gas volumes (surface units), and volumes-in-place (reservoir barrels) are extracted from the model output at each time step. An EOS program is used to compute the surface quantity of injection gas theoretically required to maintain constant pressure. This quantity is used, in conjunction with the amount of gas actually injected, to calculate VRR for each region and time step. The numerical simulator can be updated on a regular basis and used as a surveillance tool to monitor reservoir energy changes and to satisfy regulatory reporting requirements. It is also used as an optimization tool to manage EOR operations.
Pressure-Transient Responses of Horizontal and Curved Wells in Anticlines and Domes
Authors: Al-Mohannadi N. , Ozkan E. , Kazemi H.
Published: December 2007

This paper presents a discussion of the pressure-transient responses of horizontal wells in anticlinal structures and curved wells in flat reservoirs. It is shown that, in the absence of gas cap, conventional horizontal-well models may be used to approximate the flow characteristics of the systems where the trajectory of the well does not conform to the curvature of the producing structure. If a gas cap is present, however, the unconformity of the well trajectory and producing layer manifests itself especially on derivative characteristics when the gas saturation increases around the well. In general, the most significant deviations from the conventional horizontal-well behavior are observed during the buildup periods following long drawdowns. In these cases, the pressure-transient analysis is complicated and requires detailed numerical modeling of the well and reservoir curvature in the vertical plane.
Monitoring Horizontal Producers and Injectors During Cleanup and Production Using Fiber-Optic-Distributed Temperature Measurements
Authors: Brown G. , Storer D. , McAllister K. , al-Asimi M. , Raghavan K.
Published: December 2007

This paper describes the application of fiber-optic-distributed temperature systems installed in several long horizontal open-hole completion intervals of production and injection wells in Oman. We demonstrate how distributed temperature data, from both types of wells, was used to optimize completion procedures and improve knowledge of the reservoir and its performance.

The Shuaiba reservoir produces 44° API oil from a low permeability micritic lime mudstone, typically 3 md. Initially, gas injection in vertical wells was selected to enhance oil recovery, but producing wells commonly experienced gas breakthrough, gas flaring was undesirable, and surface-compression constraints were encountered. For these reasons the operator decided to phase out gas injection and use line-drive water injection from horizontal wells. Wells were drilled horizontally, with up to 5,000-ft open-hole completions, but varied in effectiveness.

Fiber-optic distributed temperature measurement systems were installed in a horizontal water injector and several horizontal oil producers during 2002 to monitor the long open-hole reservoir intervals during well startup, production, and injection. Data from the fiber optic water injector showed that the intervals flooded slowly from the heel to the toe over a period of months, giving the operator improved knowledge of reservoir sweep from this type of completion. The first oil producer exhibited slow cleanup from the heel, enabling a change in pre-production well stimulation procedures to improve cleanup.

The results demonstrate that it is possible to monitor long horizontal open hole intervals continuously, during both clean-up and production, without the need for multiple well interventions. This has proved a safe and cost effective solution to improve the operators understanding of the performance of horizontal wells drilled in the Shuaiba reservoir. Substantial savings are expected through DTS surveys, with a one-time installation costs comparable to a coiled tubing run production log. Following the installation, DTS is available to provide survey data for life of the completion. It is not only cost effective, but also data acquisition operation is much less risky.
Valhall Field: Horizontal Well Stimulations "Acid vs. Proppant" and Best Practices for Fracture Optimization
Authors: Olson Karen E. , Olsen Eivind , Haidar Sami , Boulatsel Alexandre , Brekke Kristian
Published: December 2007

Proppant fractures along the horizontal laterals in the Valhall Field have become a standard completion method for the last eight years with over 150 proppant fractures completed to date. The development of the flank regions of the Valhall Field began, with the first of 14 wells completions, in March 2003. Lateral lengths of up 2,000 meters will be drilled from two new platforms placed on the North and South edges of the field. The chalk formation in the flank regions is expected to be more competent then the crestal part of the field, so the question was raised as to whether fracturing should be done with acid or proppant. From a proppant fracturing perspective, each flank well will require between 10 to 14 prop fractures along its lateral requiring 2.5–3.7 Million pounds of proppant per well.

Three different methods have been used to determine whether the wells should be acid or proppant fractured. These consist of reviewing the historical well performance, analytical and numerical modeling. All three methods clearly showed proppant fracturing was the preferred stimulation for the Valhall Field regardless of it's location. Acid fracturing becomes the stimulation of choice only if the well does not come in contact with enough OOIP (e.g. 5 MMSTB) to justify the proppant fractures.

Proppant fracturing is expensive, so in conjunction with identifying the best stimulation method for the flank region, optimization with respect to fracture spacing along the horizontal lateral, fracture length and width have been numerically modeled for both the crestal and flank wells. This is an evolving process that should be considered an industry "Best Practice" as it enables real time optimization of ‘prop’ fracturing along a horizontal lateral during the drilling and completion phase. Since the start of this "Best Practice" in 2002, the wells stimulated in the crestal part of the Valhall Field have had the highest productivity in the field's history.
Fracture Design, Execution, and Evaluation in Retrograde Condensate Reservoirs: Case History of the Angsi Field, Offshore Malaysia
Authors: Murrey Michael D. , Cipolla Craig L. , Nor M. Nazri M. , Manzoor Hussain Wukar Hussain
Published: December 2007

This paper details the evolution of hydraulic fracture design, execution, and evaluation in the Angsi field, Offshore Malaysia. The primary target for propped hydraulic fracturing treatments is a 660 ft thick series of stacked fluvial sandstones at an average depth of 8500 ft-TVD, designated the K-sands. The K-sands are high temperature (320ºF), over-pressured retrograde gas condensate reservoirs ranging from 10 to 90 ft net thickness and 0.1 to 3 mD. Multi-staged propped hydraulic fracture treatments are required to improve well deliverability and to mitigate the detrimental effects of condensate dropout on well performance.

The initial treatment screened out very early in the job. Fortunately, extensive diagnostic data were gathered to evaluate the treatment – including temperature and radioactive tracer logs, mini-fracs with real-time BHP and BHT, memory gauges that provided accurate BHP data for the propped treatment, and comprehensive fluid QC and rheology (Fann 50 on the platform). The integration of the diagnostic data with fracture modeling and engineering analyses indicated that the screen-out was caused by a combination of complex fracture growth and low fluid viscosity. The Angsi treatment strategy was subsequently changed to mitigate and control the problems associated with complex fracture growth, which included increasing fluid viscosity, using proppant slugs, and optimizing the perforation placement. The changes in treatment strategy implemented after the initial early screen-out resulted in the successful placement of 38 of the subsequent 41 treatments (93% success). Success is defined as placing 90% or more of the designed proppant volume.

Fracturing operations were significantly improved with the introduction of "live annulas" fracturing after the initial well, resulting in cost savings of at least U.S. $10 million in the first year. Live annulus fracturing also provided "real-time" BHP measurement that resulted in better treatment control and evaluation. Treatment designs were continuously improved throughout the program, increasing both fracture length and conductivity and improving K-sand interval coverage. The success of the first phase of the fracturing program resulted in gas production of over 190 MMCFD initial capacity and 8,200 BCPD.
Casing Running Challenges for Extended-Reach Wells
Authors: Mason Colin J. , Lopez Jesse , Meling Sigve , Munger Robert , Fraser Barry
Published: December 2007

Running long production casing strings in extended-reach wells is usually recognised as one of the most critical of all well operations. Failure to reach target depth often has a profound consequence on well deliverability and overall cost. In this paper, an overview on the status of current casing running tools and techniques is given. This is complemented with an assessment of the impact of drilling technology on the ability to run casing.

The systematic collection of quality data and application of consistent analysis techniques can help identify common factors associated with both casing running success and failure. Results are given, where this approach has been applied to two current extended-reach developments.
A Streamline-Based Method for Assisted History Matching Applied to an Arabian Gulf Field
Authors: Agarwal Bijan , Blunt Martin
Published: December 2007

We present a streamline-based history matching method 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 bubble point with present injection rates of 320,000 BWPD.
A Deconvolution Technique Using Fast-Fourier Transforms
Authors: Cheng Yueming , Lee W. John , McVay Duane A.
Published: December 2007

We present a deconvolution technique based on a fast-Fourier-transform algorithm. With the new technique, we can deconvolve "noisy" pressure drawdown and buildup test pressure-time data (distorted by wellbore storage) and "noisy" rate data. The wellbore storage coefficient can be variable in the general case. In cases with no rate measurements, we use a "blind" deconvolution method to restore the pressure response free of wellbore storage distortion. Our technique detects the afterflow/unloading rate function using Fourier analysis of the observed pressure data.

The technique can unveil the early time behavior of a reservoir system masked by wellbore storage distortion and it thus provides a powerful tool to improve pressure transient test interpretation. It has the advantages of suppressing the noise in the measured data, handling the problem of variable wellbore storage, and deconvolving the pressure data without rate measurement.

We demonstrate the applicability of the method with a variety of synthetic and actual field cases for both oil and gas wells. Some of the actual cases include measured rates (which we use only for reference purposes) and others do not.
Planning and Interpreting NMR Fluid-Characterization Logs
Authors: Minh Chanh Cao , Heaton Nick , Ramamoorthy Raghu , Decoster Eric , White Jim , Junk Elmar , Eyvazzadeh Ramsin , Al-Yousef Osama , Fiorini Rosaura , McLendon Darren
Published: December 2007

This paper presents a logical approach to ensure successful nuclear magnetic resonance (NMR) logging for fluid-characterization purposes. Numerous examples are shown in a three-stage process consisting of a) planning, b) processing and interpretation, and c) validation and integration.

First, modeling is performed to assess the NMR contrast, using any available information concerning anticipated fluid types. Knowledge of downhole conditions also allows the estimation of the NMR signal-to-noise ratio (SNR) from which the sensitivity and statistical error can be evaluated. The outcome of the planning process is a suite of NMR pulse sequences that optimizes resolution of the different fluids and minimizes error with the shortest possible acquisition time.

Interpreting fluid-characterization NMR logs is relatively straightforward when the fluids have large NMR contrast and obey the standard correlations. However, dissolved gas, wettability variations, internal field gradients, and restricted diffusion can cause deviations from model behavior and have significant effects on NMR relaxation data. These effects need to be recognized and accounted for.

To gain insights into the NMR-based fluid evaluation process, we have developed a model-independent technique that gives various sets of D-T1-T2 maps. The maps are analogous to the crossplots commonly used in log interpretation practices and are indispensable in the interpretation of the data. We also explain quantitative interpretation techniques from D-T2 maps.

Integrating NMR fluid-characterization results with other information and openhole logs constitutes the final step. As with any technique, results need to be crosschecked with other log data for consistency. The answer gives a water saturation that can be verified with other tools and techniques such as the dielectric log, resistivity logs, and the density magnetic resonance technique method.
Comprehensive Transient Modeling of Sand Production in Horizontal Wellbores
Authors: Nouri Alireza , Vaziri Hans , Belhaj Hadi , Islam Rafiqul
Published: December 2007

The design of the most appropriate completion technique for a horizontal wellbore is still a formidable task. The choices are whether to opt for an openhole or a cased completion and, whether to gravel pack or there will be no need for sand production control under prospective operational conditions. This paper introduces a predictive tool that forecasts not only the initiation of sanding, but also its rate and severity in real time. All possible failure mechanisms including shear, tensile and volumetric have been included in the proposed model. Experimental data on large block tests are used to support the validity of the proposed numerical model.

A series of well-documented experiments on a large size horizontal wellbore was numerically simulated utilizing a finite difference package. The model covers the interaction between fluid flow and mechanical deformation of the medium, capturing all possible mechanisms of failure. Providing the means of encompassing the sequential nature of sanding and the direct modeling of progressive character of the cavity, the suggested model is the first to be reported using a fully coupled transient simulation approach. The removal process of the qualified elements is simulated in the model, and the criteria that are used for this process are in accordance with the physics of sand production. This numerical tool can be used to address the main factors related to sand production problem that include the conditions under which sanding takes place and how extensive if indeed it occurs.

The model shows excellent agreements with experimental results in terms of borehole deformation and sanding rates. The model predicted initiation of shear failure from the sides of the borehole and its propagation to the top and sides of the sample. Likewise, it became evident that removal of the failed material during production may trigger more sanding through development of shear failure to the formerly intact material that may continue to fail accordingly. More importantly, the agreement between the numerical and experimental well face deformation as well as sanding rate and volume suggests that an accurate prediction of sanding can be made by using the proposed numerical modeling. Therefore, a sound decision in completion selection and sand control strategy can be suggested. Avoiding unnecessary gravel packing, and other sand controlling and prevention techniques can be achieved by utilizing the proposed model, which in turn reduces the cost of well completion dramatically. In addition, the production decline due to gravel void throat block by fine movement can be prevented. A wide use of the proposed model is expected immediately in the oil industry.
ANUMET: A Novel Wet Gas Flowmeter
Authors: Falcone G. , Hewitt G. F. , Lao L. , Richardson S. M.
Published: December 2007

Wet gas metering is rapidly establishing itself as a special problem area within the more general area of multiphase flow metering. In fact, while attempts are being made across the Oil and Gas Industry to define the boundaries between humid gas, gas-condensate and high GVF (gas volume fraction) multiphase systems, a few commercial wet gas meters are already available for specific field applications.

A major interest of Imperial College has been the development of metering schemes for three-phase (oil-gas-water) flows in oil-field production systems. Imperial College has already developed a flow meter (MIXMETER)1, which performs satisfactorily in the range of gas volume fractions of 0 to 90%. Imperial College has therefore been recently developing a new concept (ANUMET), which shows some promise for measuring two-phase flows at much higher gas volume fractions.

The technical description of the ANUMET wet gas meter is outlined in this paper. Preliminary experiments on this new metering concept have been carried out with air-water flows in a 32 mm diameter tube in the LOTUS (LongTUbeSystem) facility at Imperial College. Encouraging results have been obtained and they are presented here.
Job Change Practices Of Petroleum Engineers
Authors: Bragg Daniel M.
Published: December 2007

Labor turnover, or job change, of petroleum engineers has long been a vexing problem for managers in the oil and gas industry, especially in major firms, and no easy solution has yet been found. During the summer of 1979, a large sample of SPE members was surveyed to gather data related to career paths and job satisfaction. The goal of the study was to gain a better understanding of the importance of various intrinsic and extrinsic job factors and the role they play in keeping engineers with one company longer.

Introduction

During the past few years, especially since the OPEC oil embargo of 1973–1974, there has developed a new dynamism in the oil and gas industry as firms have shifted their business strategies in response to the new demands of the times. One effect of these new demands and shifts has been an increase in the rate of formation of small "independents" in the industry, who compete with the "majors" for the limited supply of petroleum engineers. This has resulted in an increase in the flow of engineers from the majors to the independents, prompting a growing concern on the part of the majors as to how to stop this "brain drain."In early March 1979, the Education and Professionalism Committee of SPE asked Texas A and M University if it would consider undertaking a study of the job change patterns or career paths of practicing petroleum engineers who were also members of the Society.
Compaction, Subsidence, and Associated Casing Damage and Well Failure Assessment for the Gulf of Mexico Shelf Matagorda Island 623 Field
Authors: Li X. , Mitchum F. L. , Bruno M. , Pattillo P. D. , Willson S. M.
Published: December 2007

This paper discusses analyses undertaken to address well failures at the Matagorda Island 623 field in the Gulf of Mexico shelf. All of the 17 development wells producing the main reservoir have experienced some form of well failure or casing damage during the past 16 years of production. A comprehensive review has been undertaken and a suite of studies conducted to determine the root cause of the failures, and to predict well life of existing wells and new in-fill wells. Based on the study, practical advice is presented that was applied in recent replacement wells. The particular merit of this paper is that it covers field problem case histories, advanced analytical approaches, and practical measures for implementing prediction results.
Producing Stress-Resistant High-Temperature / High-Pressure Cement Formulations through Microstructural Optimization
Authors: Mueller Dan T.
Published: December 2007

The economic success of a well construction is contingent upon establishing zonal isolation within the cemented wellbore. The concentration of stress within a wellbore produced by temperature/pressure fluctuations, hydraulic fracturing/perforating operations, dynamic forces imparted during drilling, formation compaction, etc. can result in the mechanical disruption of the cement sheath. These effects are amplified in a high-temperature high-pressure (HTHP) well environment. As such, managing, minimizing, and mitigating zonal isolation loss under HTHP conditions is the focus of considerable research efforts within the ranks of both operators and service companies.

This paper describes cement systems exhibiting very high tensile and flexural strength values in a HTHP curing environment. These stress-resistant systems are produced by simple addition of coarse (100-mesh) silica sand into the slurry design. The coarse silica serves to direct the fracture propagation along a tortuous path within the cement matrix, producing a non-linear fracture path compared to the essentially linear fracture pattern observed in conventional HTHP cement containing fine silica.

This paper introduces the general concept of mechanical property enhancement of a well cement by taking advantage of the interfacial transition zone (ITZ) produced within the set cement matrix. The ITZ serves to direct the fracture path in such a manner as to spend the applied fracture energy over a greater distance within the cement matrix. Such fractures are also wider than those produced in fine silica – cement matrices.
Analysis of Tensile Strength Test Methodologies For Evaluating Oil and Gas Well Cement Systems
Authors: Heinold Thomas , Dillenbeck Robert L. , Bray Windal S. , Rogers Murray J.
Published: December 2007

Efforts to produce better annular isolation for oil and gas wells resulted in the development of methods to quantify the induced stresses that may occur within the cement sheath of a well. Along with the ability to calculate induced stresses in a cemented annulus, is the realization that typically, if there are sufficiently induced stresses to cause a mechanical failure of the set cement, failure will likely be of a tensile nature. While the ability to predict the compressive and the tensile stresses likely to be induced in a cemented annulus is certainly a step forward for the ability to provide better fit for purpose cementing designs, it also tends to highlight a larger challenge. Specifically, even though the American Petroleum Institute (API) and the International Organization for Standardization (ISO) established recommended methods for the testing of oil and gas well cement compressive strengths, no similar standards currently exist for the testing of the tensile strength of oil and gas well cements. Without the ability to test an oil or gas well cement tensile strength in an accurate and repeatable manner, it becomes very difficult for design engineers to utilize induced stress data to determine if a given cement system possesses sufficient tensile strength to resist the induced tensile stresses.

This lack of standardized tensile strength testing has led the oil and gas industry to adopt various tensile strength test methods that were originally developed for the construction concrete industry. The authors have used many of these different tensile strength test methods and devices in their own work. They discovered that very often, a cement system can yield widely different tensile strengths when tested with different procedures. In this paper, the authors review the basic construction concrete tensile tests most commonly used in the oil and gas cementing industry, and then analyze the tensile strength results obtained with the different testing methodologies. Correlations are developed between the tests that allow design engineers to better compare cement systems when the subject slurries have been tested with different tensile strength test methods.