bluuebunny/crossref_metadata_2025 huggingface dataset:
Applying Risk Analysis to Casing While Drilling
Authors: Houtchens B. , Foster J. , Tessari R.
Published: December 2007

Engineers and managers make decisions related to drilling operations every day that must balance the risk of various alternatives. These decisions may be based on a mental, experienced based risk model that has been developed over years of decision making. However, many companies are moving to explicit risk models where risk and its economic impact are quantified. Risk is composed of two components: the probability of an event occurring and the economic consequences if it occurs. This modeling uses a logical progression to predict economic impact of trouble events such as well control, loss of circulation and sticking of the drill string or casing string.

Applying a risk model to new technology is difficult because there is no experience base for quantifying either the probability of an event occurring or the consequences of the event. This is particularly true when the technology has operational components that go against normal practices. Such is true with Casing while Drilling. Casing is used as the drill string to solve problems that one would normally expect to be made worse by drilling with a smaller wellbore clearance, higher annular velocity, and little ability to make conditioning trips.

This paper will show the results of more than 280 wells and over two million feet of hole drilled with casing over the last eight years. Comparisons will be made to conventional drilling methods in several of the areas where the technology has been applied. Elements of study include casing fatigue, casing wear, tool reliability, underreamer durability and reliability, differential sticking, lost circulation induced by increased ECD, acceptable penetration rates, etc. Results of these wells in difficult drilling areas show positively that drilling with casing is more efficient and encounters less trouble time than conventional drilling, saving operators both time and money. These savings can be seen in daily operating costs, personnel safety and in insurance premiums for the operators and drilling contractors.
Drilling, Completion, and Openhole Formation Evaluation of High-Angle Wells in High-Density Cesium Formate Brine: The Kvitebjørn Experience, 2004–2006
Authors: Berg Per Cato , Pedersen Erik Sandtorv , Lauritsen Åshild , Behjat Nader , Hagerup-Jenssen Siri , Howard Siv , Olsvik Gunnar , Downs John D. , Harris Mike , Turner Jim
Published: December 2007

Drilling and completion fluids based on cesium formate brines were selected by Statoil for use in the development of the high pressure high temperature Kvitebj0rn field. Cesium formate brine was selected primarily to minimize well control problems and maximize well productivity. These important benefits had been recognized by Statoil in previous HPHT drilling and completion operations over the past 5 years. The use of the same fluid system for both drilling and completion gives the additional benefits of simplified operations, reduced waste, and elimination of fluid incompatibility problems.

The challenge on the Kvitebj0rn field was to drill long deviated well paths through significant sequences of shales into reservoirs with pressures of up to 81 MPa (11,700 psi) and temperatures up to 155°C (311°F). So far the cesium formate brine has enabled the successful drilling, completion, and logging of 7 high angle HPHT production wells on Kvitebjørn, two completed with a cemented perforated liner and five with sand screens.

Additionally, an extended-reach exploration well was drilled from the Kvitebjørn platform to the Valemon structure. The 705 m (2,313 ft) long reservoir section of this 7,380 m (24,213 ft) long well with an inclination of 69°, was successfully drilled with the same cesium formate fluid system.

In all these wells the cesium formate brine system once again demonstrated clear performance benefits such as very low ECDs, moderate to high ROPs, good hole-cleaning, and excellent wellbore stability while logging. Quick, trouble-free, safe, and robust completion operations were also accomplished, and the wells that have been put on production show high production rates with low skin.

Full open-hole formation evaluation of the Kvitebjørn reservoir has been carried out with LWD tools. The evaluation has been aided by the development of a novel logging interpretation solution for a LWD density tool, in which the extremely high photoelectric effect of cesium-rich filtrate plays a vital role. Using photoelectric factor and bulk density data, combined with resistivity measurements from both the LWD drill pass and the ream pass, produces a very reliable and consistent net reservoir definition. The final interpretation result matches the core porosity from different lithologies in 3 different wells.

Cesium formate brine has helped Statoil to achieve a remarkable record of zero well control incidents in all 15 HPHT drilling operations and 20 HPHT completion operations in the Kvitebjørn, Kristin, and Huldra fields over a period of 5 years.
A New Drillstring Fatigue Supervision System
Authors: Vincké O. , Averbuch D. , Tollet S. , Lefevre B. , Dupuis D.
Published: December 2007

With the development of complex wells, extended reach wells and deep wells (for deeply buried reservoirs production), drillstring elements are subject to several kinds of cyclic stresses. Eventhough such stresses are often below the material endurance threshold, the induced fatigue accumulation over time may generate the failure of drillpipes while drilling.

Harsh drilling conditions would ideally require an advanced follow-up of the fatigue of each element of the drillstring. Tracking the mechanical and dynamic history of each drillstring element all over its life -from one site to another- is a challenge.

To reach this objective, the team project regrouping experts from IFP, Cybernextix, Vam Drilling and Pride International has developed a new way to monitor the fatigue of each element of the drillstring. The proposed method is based on a RFID (Radio frequency identification) chip (called tag) used in association with a modeling approach to accurately estimate the fatigue damage.

Pertinent parameters are estimated by modeling, based the operational context, and are written afterwards on the referenced element tag associated with each element of the drillstring. Reading of the identification number and the updating of the memory with new information about fatigue duration, etc., are automatically performed while the drillstring element goes through the rotary table upwards.

This new system and its first rig tests are discussed in this paper.
Optimization of Deep Drilling Performance: Benchmark Testing Drives ROP Improvements for Bits and Drilling Fluids
Authors: Judzis Arnis , Bland Ronald G. , Curry David A. , Black Alan D. , Robertson Homer A. , Meiners Matthew J. , Grant Timothy C.
Published: December 2007

A critical cost in future deep oil and gas recovery is the cost to drill a well. This cost is dominated by the rate of penetration (ROP) that becomes increasingly important with increasing depth. Improving the technology of drilling and increasing the ROP will lower the cost to drill a well. This improves the economics of deep exploration and development, potentially increasing drilling activity, increasing production and supply, lowering the cost to the consumer and improving the economy.

Industry partners and the U.S. Department of Energy (DOE) successfully completed benchmark testing of advanced diamond bits and high pressure/high temperature (HP/HT) drilling fluids at high pressures. The paper describes the results of this testing and identifies factors limiting ROP performance at great depth, and the development of drilling fluid systems and bit design philosophy to significantly improve drilling performance. Benchmark results match very well with data from target field applications. This project is part of the DOE Deep Trek program.

Sixteen full-scale tests of 6 inch bits were conducted at wellbore pressures greater than 10,000 psi. Results from high-pressure tests with water and base oil showed very high ROPs are possible before mudding up. When drilling through hard sandstone penetration rates can drop 70 to 80% on switching to a weighted mud. These data emphasize the importance of mud technology in high-pressure applications. Performance of polycrystalline diamond compact (PDC) bits showed in many cases substantial improvements over roller cone insert bits.

Cuttings from Carthage marble and Mancos shale appear to be compressed agglomerates of fine particles and Carthage marble cuttings had low compressive strengths.

The study has concluded that opportunities for improvements in both bit design and smart HP/HT drilling fluids are possible. While rock properties change continuously with pressure the cutting mechanisms at great depths change much more dramatically. Changes in bit design and mud composition, using next generation technology, will be evaluated in Phase II testing.

The significance of improved ROP for deep oil and gas plays include opportunities to reduce well costs and improve the economics of deep exploration and development plays. The net result for operators is cost reduction as well as an improved position on reserves.
Hydraulic Fracturing Down Under
Authors: McGowen J. M. , Gilbert J. V. , Samari E.
Published: December 2007

This paper reviews the fracturing history in the Cooper Basin and summarizes the results of over 650 fracturing treatments characterised by high tectonic stresses, high fracturing pressures, high reservoir temperatures, and stacked reservoir lithologies of sands, shales, and coals. Initial treatments targeted multiple moderately high permeability (1-10 md) formations, while multi-staging operations are now targeting single, less extensive, lower quality reservoirs. The paper discusses the techniques used for predicting and designing for natural fracture leakoff, high near wellbore pressure losses and high fracture gradients. It shows the changes in fracturing ideologies and how they have altered the completion strategies, predicted fracture geometries, fracturing materials, treatment schedules, and post-frac production.
Laboratory Evaluation of an Innovative System for Fracture Stimulation of High-Temperature Carbonate Reservoirs
Authors: Nasr-El-Din H. A. , Al-Zahrani A. , Still J. , Lesko T. , Kelkar S.
Published: December 2007

Acid fracturing is the commonly applied stimulation technique in low permeability carbonate reservoirs. Achieving adequate fracture length is challenging due to the fast acid spending rates and high leakoff resulting from these treatments. The problem is exacerbated when treating high temperature formations and compounded with the difficulty of providing adequate corrosion control. In addition, the health, safety and environmental implications of acid handling at surface and shortage of hydrochloric acid in certain regions must also be considered to fully appreciate the challenges imposed by acid fracturing operations. The industry has successfully tried different methods to deal with each, or a combination, of these problems. However, none of them fully address all of the challenges discussed.

This paper describes a detailed laboratory evaluation of an innovative, solid-based acid fracturing system to address the above-stated limitations of conventional systems. Extensive laboratory studies, which included acid capacity, etching patterns, conductivity measurements, solubility of reaction products, reaction kinetics, and corrosion tests were conducted at temperatures up to 300°F. The studies demonstrate that the new system results in heterogeneous etching and wormholing in both limestone and dolomite rocks. In addition, this material exhibits increased fluid efficiency as compared to conventional acid fracturing systems, with the potential of achieving heterogeneously etched half-lengths that approach the length-scale achieved with traditional proppant fracturing operations.

This paper will demonstrate the applicability of the novel solid-based acid fracturing treatment. Additionally, the paper will highlight some of the unique challenges of placing a solid-based acid system in the formation and the engineering steps taken to mitigate these challenges. Finally, application limitations of the system will be discussed.
Enhanced Fracture Entry Friction Analysis of the Rate Step-Down Test
Authors: Massaras Leon V. , Dragomir Alexanndru , Chiriac Daniel
Published: December 2007

The procedures of the Rate Step-down Test (RST) also referred to as "Step-Down Test" (SDT), and of Conventional Fracture Entry Friction (FEF) Analysis have been used worldwide for over 15 years to separate the Measured Total System Friction (MTSF) into constituent components. The magnitude of the FEF components has served as guidance to design and/or modify the placement procedure and treatment schedule, in order to reduce unplanned terminations (screenouts) of propped hydrofrac treatments.

Conventional FEF Analysis has inherent limitations which produce non-unique (somewhat erroneous) results that can only be overcome with Enhanced FEF Analysis methodology; which bypasses these limitations with innovative methods: appropriately corrected fluid friction factors, non-uniform perforation discharge coefficient, application of Maximum Drag Reduction (MDR) asymptote, and, matching of MTSF with Calculated Total System Friction (CTSF) at all rates of the RST. Several RST examples are analyzed with FEF Analyzer to illustrate and document the success in placing safe and effective propped hydrofrac treatments.

Real-world analogies are used as visual aids to explain the complex processes of FEF, along with RST design methodology, RST execution procedure, and detailed calculation procedures for performing Enhanced FEF Analysis.

Net-pressure history matching is significantly improved, due to the increased accuracy of calculating the magnitudes of the wellbore friction and of the FEF components.
Extrapolation of Laboratory Proppant Placement Behavior to the Field in Slickwater Fracturing Applications
Authors: Woodworth T. R. , Miskimins J. L.
Published: December 2007

Low-viscosity slickwater treatments are a popular hydraulic fracturing technique in low permeability reservoirs. Slickwater treatments can provide adequate conductivity in tight gas sand operations at comparatively low costs, and wells treated with low-viscosity slickwater often produce better results than those treated with cross-linked fluids in low permeability situations. Theoretically, proppant transport is poor in low-viscosity slickwater type fluids. Improving the understanding of proppant transport capabilities of slickwater would be beneficial to many operators if the cost or performance were not endangered. Improved proppant transport would result in longer propped fracture half-lengths and more favorable conductivity.

Laboratory experiments performed by STIM-LAB, Inc.'s Proppant Consortium show proppant falls from suspension and builds a proppant mound before any form of proppant transport takes place. Clean fluid stages pumped between sand-laden stages were shown to erode proppant from the proppant mound. These results formed the basis for the development of power and bi-power laws to describe the transport. These laws and the results of the laboratory experiments were used to perform sensitivity analysis to determine the relative effects of fluid viscosity, fluid density, pump rate, proppant diameter, proppant density, proppant concentration, and fracture width on slickwater treatments in the field.

Using the power and bi-power laws, the resulting sensitivity analysis, and the laboratory observations, experimental slickwater schedules were designed and field tested. A total of five experimental slickwater fracturing treatments were performed. Production data from each experimental slickwater treatment and well were compared to offset data to determine any possible effects from improved proppant transport. Production results from the field trials, including both initial production (IP) rates and early cumulative production totals, indicate significant improvement when compared to offset wells.
Numerical Simulation of Hydraulic Fracturing in the Viscosity Dominated Regime
Authors: Bunger A. P. , Detournay E. , Garagash D. I. , Clarkson U. , Peirce A. P.
Published: December 2007

Most hydraulic fracturing treatments are in the viscosity-dominated regime. Hence, fracture growth does not depend on the rock toughness and it can be shown that the fracture aperture w near the fracture front, when viewed at the scale of the whole fracture, is not characterized by the classical square root behavior predicted by linear elastic fracture mechanics w ∼ s1/2, where s is the distance from the tip. Instead, the asymptotic tip aperture that reflects the predominance of viscous dissipation is of the form w ∼ s2/3, under conditions of large efficiency and small fluid lag. After demonstrating the intimate connection between the tip aperture and the fracture propagation regime, we report the results of hydraulic fracturing laboratory experiments in PMMA and glass blocks that employ a novel optical technique to measure the fracture opening. These experiments provide incontrovertible evidence that the power law index, characterizing the fracture aperture near the tip, depends on the propagation regime in accordance with theoretical findings. Finally, we demonstrate that a coarsely-meshed planar hydraulic fracture simulator can produce accurate results relative to benchmark solutions provided that the appropriate tip behavior is embedded in the algorithm. Through theoretical, experimental, and computational considerations, these results make it clear that advances in the accuracy and efficiency of fracture simulators critically depend on a sophisticated treatment of the near-tip aperture that goes beyond basic linear elastic fracture considerations.
Case Studies of Propped Refracture Reorientation in the Daqing Oil Field
Authors: Wang S. G. , Zhang G. L. , He X. Q. , Liu X. , Hou F. , Cui T. X.
Published: December 2007

This paper presents case studies of re-fracture treatments and reorientation measurement results by surface tiltmeter mapping in the Daqing oilfield. All the four treatments in this study included a novel design technique of pumping paraffin balls approximately half way through the propped treatment in an attempt to initiate fracture growth in a different orientation or through different perforation intervals. Tiltmeter mapping results indicated that fracture reorientation occurred for the majority of the re-fracture treatments studied.
A Singular Evolutive Interpolated Kalman Filter for Rapid Uncertainty Quantification
Authors: Liang Baosheng , Alpak Faruk O. , Sepehrnoori Kamy , Delshad Mojdeh
Published: December 2007

Inherent data and model uncertainties render the history-matching inverse problem extremely non-unique. Therefore, a reliable uncertainty quantification framework for predicting reservoir dynamic performance requires multiple reservoir models that match field production data. It has been previously demonstrated that the ensemble Kalman filter technique can be used for this purpose. In this technique, an ensemble of reservoir models is evolved by means of a stochastic nonlinear filtering procedure to agree with the observed production data. An efficient variant of the ensemble Kalman filter, namely, Singular Evolutive Interpolated Kalman Filter (SEIKF) is applied to the multi-model history-matching problem in this work. This novel technique operates in three steps: resampling, forecasting, and assimilation. Unlike the ensemble Kalman filter, where the members of the model ensemble are operated by forecasting and assimilation, in SEIKF, the members of the model ensemble are selected in the main orthogonal directions of a functional space described by an approximation to the error-covariance matrix. This enhanced sampling strategy, embedded into the resampling step, improves the filter stability and delivers rapid convergence.

SEIKF is applied to a three-dimensional proof-of-concept waterflooding case where reservoir permeability is calibrated to production data. Accuracy and convergence of history match as well as the uncertainty of dynamic predictions yielded by the final model ensemble are used as criteria to evaluate the performance of SEIKF. The outcome of the proof-of-concept studies quantitatively demonstrates that SEIKF exhibits rapid convergence in the domain of model parameters. In terms of accuracy and uncertainty reduction, SEIKF performs comparable to a conventional ensemble Kalman filter. SEIKF promises a rapid and reliable framework for history matching and naturally lends itself to uncertainty quantification.
Prediction of Long-Term Proppant Flowback in Weak Rocks
Authors: Aidagulov G. R. , Thiercelin J. , Nikolaevskiy V. N. , Kapustyanskiy S. M. , Zhilenkov A. G.
Published: December 2007

Proppant flowback is an extremely important phenomenon in hydraulic fracturing technology and may cause severe problems for well completion. Various models have been developed to predict the onset of proppant flowback but the physics of the phenomenon has still to be understood to predict the amount of proppant flowback during the life of a well. In particular, determining whether the proppant flowback will stop after a few days of production or will continue at a given rate during the well's life is a key issue when selecting an appropriate completion method. The development of a model allowing a quantitative prediction of this process is therefore a very vital task. In this paper we present a quantitative model to predict proppant flowback. The model is based on treating both the proppant pack and the reservoir as poroelastoplastic media. It allows for solid production from the proppant pack but also from the formation itself in case the fracture was created in a very weak reservoir formation.

According to this model, the fluid and rock skeleton are considered as two interpenetrating continua. The Mohr- Coulomb yield criterion with the non-associated plasticity rule written in terms of the Terzaghi effective stress is used to describe the flow of a solid matrix connected with the pore pressure gradient.

The influence of proppant properties, rock properties, in-situ stress, fracture width, and flow rate on proppant flowback is studied to determine the controlling parameters. It is shown that when a severe proppant flowback problem occurs, the closure stress around the wellbore is significantly altered. In some cases, the fracture width at the wellbore is decreased leading to the cessation of solid production, while in others continuous production is maintained. It is shown that the selection of proppant properties is an efficient way to control flowback, but obviously the requirement in terms of strength depends on the downhole conditions.
Shear Dilation Diagnostics: A New Approach for Evaluating Tight Gas Stimulation Treatments
Authors: Chipperfield S. T. , Wong J. R. , Warner D. S. , Cipolla C. L. , Mayerhofer M. J. , Lolon E. P. , Warpinski Norman Raymond
Published: December 2007

Many tight gas reservoirs require fracture stimulation to achieve commercial outcomes. These reservoirs can often be characterized geologically and geomechanically by high deviatoric stresses and hard, naturally fractured rock. Stimulation treatments in such reservoirs may create complex fracture networks from a combination of shear and tensile failures. Water fracs can be used where shear failure is anticipated to dominate. However, in these environments few practical modeling tools exist to determine [1] the level of permeability enhancement, [2] the degree of permeability retainment during drawdown and [3] the Stimulated Rock Volume (SRV). This paper seeks to provide the engineer with a suite of tools capable of achieving these goals.

This paper presents a dual porosity, pressure dependent permeability reservoir simulation model that was devised to honor shear failure mechanisms [also called shear dilation] using basic geological characterization. The assumptions of this model and the pragmatic selection of first order effects are discussed. Using the results of this simulation model, three families of diagnostic tools are presented.

The first category is that of Treatment Diagnostics (TD) which include bottomhole pressure evaluation, injectivity and fall-off analysis. The second approach is called Seismic Based Reservoir Characterization (SBRC), which uses the microseismic to determine the SRV as well as provide estimates of the initial and stimulated fracture network properties. The third category is Post Treatment Diagnostics (PTD), which incorporates the evaluation of pressure drawdown characteristics.

Finally, this paper compares these individual approaches and provides a workflow to evaluate data on future wells.
Production Data Analysis for Commingled Multilayer Gas Reservoirs—Graphical Aides for Flow Regime Identification and History Matching
Authors: Spivey John P.
Published: December 2007

Most of the major unconventional gas plays in the U.S. have multiple productive intervals. Wells are completed with multiple fracture treatments, and are produced commingled.

An earlier paper1 described a single-well, multilayer, analytical reservoir simulator* for estimating individual layer properties in multilayer unconventional gas reservoirs by automatic history matching production and spinner survey data simultaneously. The present paper describes several interactive graphical aides that greatly facilitate the history matching process when used in conjunction with the analytical, multilayer reservoir simulator. These graphical tools include an allocation graph and layer and cumulative production log graphs. These graphs allow the engineer to quickly review the quality of the match at any point during the history matching process.

Use of these graphical tools has improved the history matching workflow to the point that a complete history match of a well with 20 frac stages, two years of daily production, and three spinner surveys can be performed in as little as four to six hours, from construction of the initial data set through completion of the final match.
Evaluation of the Elliptical Flow Period for Hydraulically-Fractured Wells in Tight Gas Sands—Theoretical Aspects and Practical Considerations
Authors: Amini S. , Ilk D. , Blasingame T. A.
Published: December 2007

It has been long established from well testing concepts that an elliptical flow pattern exists in hydraulically-fractured wells producing from low permeability (<0.01 md) and ultra-low (<0.001 md) formations (often referred to as "tight gas" or "shale gas" sands). Conceptually, the elliptical flow period is a transitional flow regime that occurs between the end of bilinear and/or formation linear flow and the onset of pseudo-radial flow. In a practical sense, the elliptical flow regime can (and does) dominate the well performance for very low permeability reservoir systems.

Elliptical flow (as with pseudo-radial flow) represents a time period when the reservoir properties begin to dominate the reservoir performance. Moreover, the duration of the elliptical flow period may last for many months, perhaps even years, depending on the reservoir and hydraulic fracture properties. Consequently, understanding the elliptical flow period and its impact on well performance is critical for the optimal development of a tight gas sand reservoir.

This paper presents a series of decline type-curves for a system consisting of a hydraulic fracture at the center of an elliptical reservoir. The curves are generated from the pressure solution obtained using an analytical method. The curves are generated for different values of the fracture conductivity and as a function of the elliptical boundary characteristic parameter (ξ0).

For the low permeability cases where the elliptical flow period dominates, the elliptical boundary characteristic parameter (ξ0) is a useful parameter for establishing the optimum well spacing and the optimal design for the drainage aspect ratio. We note that the ξ0-parameter essentially reduces the optimization process for tight gas reservoirs to a single parameter that should yield the optimum configuration for drainage and production performance. Obviously the fracture conductivity is also a major factor, as is the reservoir permeability and the fracture half-length — but the ξ0-para-meter is the key to recovery and performance in systems dominated by elliptical flow behavior.
Liquids Phase Holdup and Separation Characteristics as a Function of Well Inclination and Flowrate
Authors: Awal Mohammad R. , Razzak Shaikh A. , Al-Majed Abdulaziz A. , Al-Yousef Hasan Y. , Zughbi Habib D.
Published: December 2007

The maturing Middle Eastern oil fields with natural aquifer support or water injection can pose a challenging produced water handling and disposal issues. The increased water-oil ratio also presents productivity problems: many wells will die prematurely due to increased water holdup. The produced water management cost @US$ 0.50—1.00 per barrel involving millions of barrels of water (even at a modest WOR of 50% from current 30–35%) will be in billions due to the high daily oil production rate envisaged. In this paper, we focus on various aspects of downhole oil-water separation, which we believe will lessen the cost significantly. The downhole water separation technology developed and applied in the western hemisphere cannot be directly applied here because of the orders of magnitude higher production rates per well.

Lacking a production flow-loop facility in the region with full-scale production equipment, we use an industry-standard commercial computational fluid dynamics (CFD) simulation tool to investigate inline oil and water separation characteristics under downhole conditions. Specifically, we investigate the startling sensitivity of well inclination in the 80–100 degrees range. We show that it is crucial to control the well inclination within a tight regime to achieve effective and manageable liquids separation in near horizontal wells. We also show that the liquids phase separation in these wells are sensitive to the gross liquids flow rate.

The CFD simulation study reported in this paper will lead to new technology development that can be used to achieve more effective well completion design in near horizontal wells drilled specifically to obtain downhole oil-water separation. The success of such innovative oil-water separation will save many producing wells from dying prematurely and save millions of dollars in produced water handling and disposal.
Field Based Criteria For The Design of Safe Mud Weight Window
Authors: Mohiuddin M. A. , Khan K. , Abdulraheem A. , Al-Majed A. , Aurifullah V.
Published: December 2007

Field based parameters like initial mud weight used for drilling, mud weight increment and problems per well were used to analyze wellbore instability, identify different instability mechanisms and design safe mud weight window for drilling horizontal wells. These parameters were used first on the drilling data of vertical wells to develop the procedure for the analysis of wellbore instability and identify the mechanism of instability. The developed procedure was then applied to the drilling data of directional wells to show the dependence of mud weight on the inclination and azimuth of the well. Finally, the procedure was applied to horizontal wells data along with the concept of critical washouts to infer the safe mud weight window. The safe mud weight window is validated on another set of drilling data showing 90% success rate.
Estimating the Amount of free Sand in the Yielded Zone around Vertical and Horizontal Oil Wells
Authors: Al-Awad Musaed N. J. , Al-Ahaidib Talal Y.
Published: December 2007

Predicting sand production accurately is a difficult task; many techniques have been previously investigated such as production history, mechanical property analysis using electrical log data, laboratory testing and computer modeling.

In this study, the mechanism of sand production problem in an oil reservoir producing medium oil (30° API) from a weak sandstone formation was investigated. An analytical model is elaborated based on linear-poroelastic solution of stress state around circular openings as well as Mohr-Coulomb failure criterion and Darcy's equations for fluid flow through porous media in vertical and horizontal wellbores.

In this study, a new important factor necessary for the estimation of the mount of free sand generated between sheared planes caused by the fluid drawdown was introduced. This factor is called sand production capability factor. Sand capability factor was evaluated experimentally for the studied reservoir.

Observations of sand production in the studied oil reservoir were utilized to tune and verify the model used in this study. For open-hole completion, it was found that; free sand ready to move into the wellbore is inversely proportional to radial distance. Furthermore, free sand ready for production from the yielded zone around vertical wells is higher than that in the case of horizontal wells. The predicted free sand in all studied cases is in accordance with field observations.

Selection of borehole and perforation orientation (in case of perforated casing completion) with respect to the maximum horizontal principal in-situ stress has a great effect in reducing the potential free sand amounts ready to move into the wellbore along with the producing reservoir fluids. Horizontal wellbores oriented at 45° produce minimum sand compared with other horizontal orientations for the studied reservoir. Similar effect is found for perforations phased at zero angular position.
Experimental Assessment of Bacterial Ability to Tackle the Wax Problem in the Crude Industry
Authors: Paitakhti Oskouei S. J. , Roostaazad R. , Ghotbi S. , Sadeghazad A.
Published: December 2007

Mesophilic bacterial specie was isolated from an active Iranian oil well and together with another available bacterial strain was evaluated in tackling the well known wax problem. Both of the strains proved to grow on the crude as the sole carbon source while supported by inorganic salts, phosphorous and nitrogen sources. The growth phases had a lag phase of less than 1 day and lasted more than 1 week before entering the stationary phases. The optimum oxygen requirements of the bacteria were not large. The isolated bacterium was successful to decrease pH from 7 to 5.5, the initial surface tension of 65 to as low as 55 dyne/cm and the wax and asphaltene content as much as 27.8% and 10.6% respectively. These effects are expected to have a positive effect on the cloud and pour points, deposition tendency of the crude and/or emulsification of deposited wax in a sweeping medium such as injected water.
New Strategic Method to Tune Equation-of-State for Compositional Simulation
Authors: Al-Meshari Ali A. , McCain William D.
Published: December 2007

Since the plus fraction of reservoir fluids has some uncertainty in its molecular weight and critical properties, equation-of-state, EOS, are generally not predictive without tuning its parameters to match experimental data. Tuning of the EOS is found to be the best method for improving the predictions of compositional reservoir simulators.

The proposed strategy for tuning EOS consists of seven steps: (1) split the laboratory plus fraction to single carbon number groups, SCN, usually up to SCN 44; the last component will be C45+, (2) use set of correlations to calculate the critical properties and acentric factor for each SCN group, (3) match the saturation pressure at reservoir temperature by altering the measured value of the molecular weight of the plus fraction using the extended composition, (4) group SCN groups to multiple carbon number groups, MCN, (5) assign critical properties and acentric factor for each MCN group, (6) rematch the saturation pressure at reservoir temperature using the grouped composition, and (7) match the volumetric data by regressing on volume shift parameters of all components in grouped composition.

This paper shows an accurate method to split the plus fraction to SCN groups. The most accurate set of correlations to calculate the critical properties and acentric factor for each SCN group that will result in a small adjustment for the molecular weight of the plus fraction when saturation pressure is matched using the extended composition. The proposed strategy groups the extended composition to eight pseudocomponents. The binary interaction coefficients between hydrocarbons and between hydrocarbons and non-hydrocarbons are set to zero which dramatically reduces the simulation time.

The strategy proposed in this paper for tuning EOS to match experimental data has been tested for a wide range of C7+ mole% (4 – 25) which covers gas condensate and volatile oil samples. The scope of this paper is to come up with an accurate and systematic technique for tuning an EOS for use in compositional simulation.
Frontiers of Formation Evaluation and Petrophysics; Present and Future Technologies
Authors: AlRuwaili Saleh B.
Published: December 2007

In anticipation of important technological advancements, during the 21st century, it is worthwhile discussing the frontiers of the current formation evaluation and petrophysics. Today, formation evaluation has limits, dictated by the available logging technologies, core-analysis expertise, petrophysical models and interpretation methods. Technological advancements in logging measurements, core-analysis or petrophysical interpretations can contribute to widening the horizon of formation evaluation and magnifying its value in the oil and gas business.

Logging technologies and services currently provided have various limitations. The resolution of the logging tools has not come below one foot. The depth-of-investigation of almost all the logging tools has not exceeded a couple of feet into the formation. Data acquisition in most of the logging tools has limited speed. Logging technologies have not yet enabled direct and continous measurements of formation permeability and electrical properties.

Similarly, there are some limitations in the petrophysical models and interpretation methods available. Deterministic petrophysics has limited capability in characterizing minerals in the formation. Non-deterministic, or probabilistic petrophysics, has prediction capability to some minerals, yet its prediction of formation minerals is non-unique. Insufficient mineralogical-description of formation lithology can introduce inaccuracy in the calculation of formation-porosity. Inadequate characterization of rocks and their types can have negative effects on estimating water-saturation and permeability in the formation. Technology and expertise enabling factual representation of formation parameters are essential for obtaining state-of-the-art formation evaluation.

Core data is considered the ground truth and can have a corner-stone role in formation evaluation. Different core-analysis laboratories could give different measurements of the same attributes from the same core. Standardization of procedures among core-analysis laboratories is highly needed for better formation evaluation and petrophysics.
Laboratory Study on Precipitation of Calcium Sulphate in Berea Sandstone Cores
Authors: Abu-Khamsin S. A. , Ahmad S. J.
Published: December 2007

Scale deposition is one of the most serious oil field problems that inflict water injection systems primarily when two incompatible waters are involved. Mixing of these waters could cause precipitation of CaSO4, BaSO4 and/or SrSO4.

To generate reaction kinetics data, the rate of calcium sulphate deposition in porous rock was measured while flooding Berea core samples of uniform properties with supersaturated brine. The brine was formulated by mixing a Ca+2-rich solution with a SO4−2-rich solution at the core inlet. The rate of CaSO4 scale formation was estimated by monitoring the core effluent's Ca+2 ion concentration. Several parameters were varied including temperature, pressure, degree of brine super-saturation, and flooding velocity.

The results indicated increased rate of CaSO4 precipitation at higher temperatures, higher flood velocities, and greater brine super-saturation, whereas pressure had a slight effect on CaSO4 deposition. The results were utilized to build a general reaction rate equation to predict CaSO4 deposition in Berea sandstone for a given temperature, brine super-saturation, and flooding velocity.
Modeling the Effects of Compositional Changes in Transient Flow of Gas Condensate Reservoirs
Authors: Olaberinjo A. F.
Published: December 2007

Gas condensate reservoirs exhibit complexities due to the production of gas, condensates and many times, in situ oil phase. As the average reservoir pressure in a gas condensate reservoir continues to decline on production, condensate drop out occurs across the reservoir. Pressure decline between the reservoir boundaries and the well bore could lead to condensate formation near the well bore.

This paper considers the flow behavior in gas condensate reservoir and presents an approach for calculating the pressure depletion performance of a gas condensate reservoir from the original reservoir fluid composition using the vapor – liquid equilibrium calculations, the fluid properties, dimensionless properties, and retrograde liquid accumulation as guides.

The results correspond to drawdown analysis of a condensate reservoir where flow of the phase occurs. It is also a compositional analysis and includes the composition of the hydrocarbon fluid up to and including C7+. The presence of non-hydrocarbon impurities such as Carbon dioxide, Nitrogen and Hydrogen Sulphide are also considered. The comparison with other standard work on transient pressure analysis from gas condensate reservoirs showed that the approach is satisfactory.

A principal use of the method would be for the initial estimation of pressure depletion pattern after discovery of a gas condensate reservoir, where the compositional analysis of the reservoir fluid may be only approximate and the dew point if not known, is assumed to be the reservoir temperature and pressure. It is also a valuable tool during the production period for reservoir surveillance and monitoring.
Next Generation Expandable Completion Systems
Authors: Innes Gareth , Morgan Quentin , Macarthur Ally , Green Annabel
Published: December 2007

This paper documents an 18-month expandable technology research and development effort that has culminated in a system that enables a new approach to reservoir architecture.

The drive for maximum well productivity compels oil and gas companies to consider openhole completion strategies. However, historical uptake has been impeded by inability to achieve effective zonal isolation. The Expandable Reservoir Completion [ERC] combines slotted and solid expandable technology and features a return to conventional unexpanded premium connections to deliver a freely configurable reservoir completion architecture, offering a combination of openhole production performance and cased hole functionality.

Fundamental to the new Expandable Reservoir Completion is a unique, selective rotary compliant expansion technique, which is used to clad the formation wall with expandable screens, slotted liner or solid tubulars with sealing units. This technique facilitates unparalleled flexibility in reservoir design by allowing sections of conventional casing to remain unexpanded between zones. This enables integration with conventional flow control and intelligent completion equipment, ultimately permitting selective isolation & production control.

This paper outlines detailed test data generated by the development program, which included three downhole field trial installations. In addition to this, information from the first global commercial installations will be presented, from pre-job planning through to post installation performance review.

The Expandable Reservoir Completion builds upon existing expandable sand screen and solid expandable technologies to deliver a combination of productivity and functionality previously unavailable to the petroleum industry.
Integrating Advanced Well Completion Technology Improved Well Performance & Maximized Recovery_Case History
Authors: Sunbul A. H. , Al-Mohanna K. S. , Al-Qahtani H. B. , Hembling D. E. , Salerno G.
Published: December 2007

The combination of two new technologies - a production equalizer system combined with in-situ gas lift or electric submersible pumps (ESP) _ have been successfully implemented in Saudi Aramco offshore oil fields to optimize well rate and recovery. Merging these technologies has allowed Saudi Aramco optimal completion methods to exploit the remaining reserves from both Khafji and Safaniyah sandstone reservoirs.

This paper describes the benefits of integrating production equalizer technology with artificial lift (In- situ gas lift or ESP) to optimize production, delay water /gas coning, ensure uniform inflow, and prolong well life. A case history from Saudi Aramco will be presented, where these integrated technologies resulted in significant saving for the operator, and improved production performance in horizontal offshore oil wells.
Core Flood Study of Injectivity Decline by Mixing Produced Oily Water with Seawater in Arab-D Reservoir
Authors: Ba-Taweel Mohammed A. , Al-Anazi Hamoud A. , Al-Otaibi Msalli , Ballan Abdel N Abitrabi , Hilab Victor V.
Published: December 2007

A study was initiated to investigate impact of co-mingling produced water with seawater. The objective of the study was to assess injectivity decline in power water injectors caused by introducing produced water into the seawater injection system using core samples from Arab-D.

A series of core flood experiments was conducted to study formation damage aspects. The core flood study was done using water samples collected from shipping lines from Qurrayah to represent seawater and produced water from HRDH GOSP-2, due to lack of actual produced water from X field. The core flood experiments were performed to assess the effect of produced oily water on core permeability.

Experimental results showed that introducing different ratios of produced water (5, 10, 15 and 100 vol.%) to the seawater resulted in permeability loss of core samples. The damage was found to be proportional to the concentration of produced water. More reduction in permeability was found in low permeability core samples. However, lost permeability was restored by reversing flow in high permeability core (83 md).

Based on the obtained results, it is recommended to inject produced water into a dedicated disposal wells to avoid any injectivity decline in power water injectors and to maintain the injection rate target of 30 MBWPD. It is also recommended to maintain a good quality of the injected seawater. Low level of oil and solids in produced water should also be maintained.
General Transfer Function for Multiphase Flow
Authors: Lu H.
Published: December 2007

We propose a physically-motivated formulation for the matrix-fracture transfer function in dual permeability and dual porosity reservoir simulation. The current Barenblatt-Kazemi1–3 approach uses a Darcy-like flux from matrix to fracture, assuming a quasi steady-state between the two domains. However, this does not correctly represent the average transfer rate in a dynamic displacement. Based on one-dimensional analytical analyses in the literature we find expressions for the transfer rate accounting for both displacement and fluid expansion. The resultant transfer function is a sum of two terms: a saturation-dependent term representing displacement and a pressure-dependent term representing fluid expansion. The expression reduces to the Barenblatt form for single-phase flow at late times, but more accurately captures the pressure-dependence at early times. For displacement we consider both imbibition and gravity drainage processes.

The transfer function is validated through comparison with one-dimensional fine-grid simulations and compared with predictions using the traditional Kazemi et al3 formulation. We show that our method captures the dynamics of expansion and displacement accurately, giving better predictions than current models, while being numerically more stable.