bluuebunny/crossref_metadata_2025 huggingface dataset:
Major Advancements in True Real-Time Hydraulics
Authors: Zamora M. , Roy S. , Caicedo H. Y. , Froitland T. S. , Ting S. -T.
Published: December 2007

Deepwater, HTHP, and narrow pressure-margin wells depend on accurate, real-time knowledge of downhole hydraulics in order to achieve their objectives safely and economically. Pressure-while-drilling (PWD) can satisfy many of the needs. However, PWD measurements are sometimes not available during certain critical operations, are restricted to the tool location, and are unable to provide the "what-should-be" scenario needed for informed decisions. These "knowledge gaps" can be filled by a newly developed wellsite computer system (WCS) designed to model downhole hydraulics behavior from surface drilling data in true real time.

The WCS has been used successfully on nine exploratory wells in the Gulf of Mexico and the North Sea, including eight drilled with narrow operating windows and four drilled in deepwater. Calculated ECDs typically were within 0.1 ppg of PWD values; and the system substituted well for PWD when tools were unavailable, inoperable, or not transmitting data to surface in real time. Also, the WCS helped guide several successful casing and liner jobs run in low-fracture-gradient environments. With no PWD tool installed, the WCS was uniquely available to provide the instant feedback needed by drillers to prevent problems before they occurred.

Relevant measured and interpreted information is graphically displayed on the WCS screen during drilling and tripping operations. Simultaneously, key parameters can be displayed at the driller’s station as if they were measured values. Calculated downhole ESD, ECD, hole-cleaning efficiency, temperature, and other hydraulics-related profiles are based on comprehensive models proven successful in a wide range of drilling applications. Considerations for transient behavior have been added in order to adapt and update the models for use in real-time environments.

Major advancements introduced during the WCS development and refined by its subsequent use are the subject of this paper. This is accomplished within the framework of hardware and software descriptions, basic modeling concepts, and multiple examples of drilling and tripping data generated during field applications. Also included is a discussion of enhancements that could be realized by improved modeling, better sensors, and expansion into related disciplines.
Reservoir Characterization Using 3D AVO and 3D Net Sand Prediction
Authors: Skidmore C. M.
Published: December 2007

The major issues that face us today revolve around economics. Finding hydrocarbons has been made easier with 3D data, but the proper delineation and quality of the deposit still often eludes us. Application of a series of amplitude attributes indicates that applying one technology, such as Amplitude Strength, is not enough. The issues that impact the economics of a reservoir are varied and complex, therefore multiple techniques must be used to address them.

Application of seismic attributes to three areas of the Gulf of Mexico, in a consistent manner, demonstrates how effective technology can be when applied properly. The three areas examined all had similar Amplitude Strength, but drilling results in the area produced varied results. The Mississippi Canyon 486 field was first examined because of the strong variation in reservoir thickness. The sixteen wells drilled in the field have gross thickness variations from 23 to 160 feet, and net thickness variations from 0 to 160 feet. Amplitude maps over the field do not indicate this complexity, and agree very poorly with the drill results. Advances in technology, mainly in the areas of AVO, Thickness, and Rock Property estimation, offer a much clearer picture of the reservoir size. Similar technology applied to a second area correctly predicted the poor outcome of an initial well and indicated the presence of cleaner and thicker reservoir in the immediate area. A sidetrack was drilled and an economic discovery was announced. The third location also has a strong amplitude anomaly similar to the other two. The AVO signature suggests the presence of hydrocarbons, but thickness predictions indicate very low net/gross sand ratios in the reservoir. The well drilled into the anomaly was plugged and abandoned.
A Multiresolution Approach to Reservoir Parameter Estimation Using Wavelet Analysis
Authors: Lu Pengbo , Horne Roland N.
Published: December 2007

In this paper, a new multiresolution approach is proposed for reservoir parameter estimation, i.e., to estimate the spatial distribution of the reservoir properties by proper integration of all types of data available (either static or dynamic). We considered the integration of production history data, seismic data and well test data in this work.

One of the key issues in parameter estimation is to develop an efficient and reliable nonlinear regression procedure. We adapted wavelet analysis to describe the distribution of sensitivity coefficients, since wavelet analysis is a powerful tool in multiresolution analysis and is widely used in signal and image processing. Wavelet analysis can compress the parameter space, stabilize the algorithm and avoid local minima. This new approach also improves the computational efficiency significantly by varying the resolution of the estimation at different regression stages.

Wavelet analysis also has the capability to integrate different types of data efficiently, using different levels of wavelets to incorporate different data types. We can account explicitly for the resolving power of different data and estimate reservoir properties with nonuniform resolution.

We have applied the procedure to multiphase reservoir examples that demonstrate the reliability and flexibility of the approach. We also gained very good convergence and excellent computational efficiency compared to conventional methods. The most important conclusion of this paper is that wavelet analysis is a very useful tool for reservoir parameter estimation and can speed up the computation and improve the performance. The nonlinear regression procedure integrating wavelet analysis has substantial advantages over the conventional algorithms.
Visualisation of Oil Recovery by Water Alternating Gas (WAG) Injection Using High Pressure Micromodels - Water-Wet System
Authors: Sohrabi M. , Henderson G. D. , Tehrani D. H. , Danesh A.
Published: December 2007

The use of WAG (water alternating gas) injection can potentially lead to improved oil recovery compared to injection of either gas or water alone, however the physical process is not well understood. Using high pressure glass micromodels, a series of WAG tests have been conducted using equilibrated fluids, with high quality images of the oil recovery processes operating during alternate WAG cycles being recorded. The tests were conducted using both water-wet and oil-wet micromodels. In this paper results of a typical water-wet test is presented (results of the oil-wet and mixed wet tests will be presented in a subsequent paper).

Water-wet micromodels were initially fully saturated with water and then displaced with oil to establish the connate water saturation. The micromodels were then flooded with water to observe the process of establishing the waterflood residual oil saturation (Sorw). Alternate cycles of gas and water injection were then conducted to observe three-phase flow and its associated oil recovery. The experiments were performed within the capillary dominated flow regime.

The results highlighted the importance of corner filament flow of water in the recovery process, with the initial waterflood residual oil saturation being trapped mainly in the centre of the majority of pore space surrounded by layers of water, and not in only large pores. The successive WAG cycles redistributed the oil in a way which resulted in improved oil recovery, hence, the oil which otherwise would not have been mobile under either gas or water injection alone was mobilised and produced.

It was identified that a limited number of WAG cycles were required to approach maximum oil recovery, after which additional recovery was minimal. All recovery processes were filmed and electronically stored using high resolution imaging, with oil recovery at the end of each flooding cycle being measured using image analysis techniques.
State-of-the-Art Interventionless Completion Technology Provides Key to Greater Cost Reduction and Completion Efficiency
Authors: Simonds Randy , Navarro Juan , Skinner Neal , Schneller Tricia
Published: December 2007

A new system for the remote, interventionless actuation of downhole completion equipment has been developed to support industry needs to lower costs and preserve asset values. The traditional methods for setting a production packer employ coiled tubing or slickline to run a tubing plug. The new system provides a safe, reliable and more cost effective alternative to traditional intervention because it simply transmits acoustic pulses through the contents of tubulars to actuate one or more completion or service tools remotely in any desired sequence.

The system not only decreases the time to set the packer but also extends the envelope for application to deep, extended-reach offshore environments. Since the system eliminates the need to circulate a ball downhole to set service tools during sand control operations, the operator can maintain constant hydrostatic pressure on the formation. This capability decreases completion time, intervention risk, the possibility of formation collapse against the completion string, the possibility of losing the filter cake placed against the formation, and fluid loss to the formation.

To achieve the goals required for this system, three project targets were addressed: a reliable means of wireless communication, a surface control system, and a downhole power unit for completion device actuation. The design and capabilities of the new surface-operated, non-intervention completion system will improve completion economics.
Design and Installation of a Sand Separation and Handling System for a Gulf of Mexico Oil Production Facility
Authors: Rawlins C. H. , Staten S. E. , Wang I. I.
Published: December 2007

A comprehensive system for the separation and handling of sand from produced fluids was designed and installed in a Chevron facility in the Gulf of Mexico. This system involves two multicone desander systems, one on the water outlet and one on the oil outlet of an LP separator, to provide separation of sand from produced fluids. The separated solids are collected, dewatered, and transported to a unique, simple solids handling system designed for complete fluid containment and safe handling. The focus of this paper is to present the design of the separation and handling system, and discuss the various challenges encountered during and after commissioning. The topics covered include desander operation (pressure drop and separation), slurry discharge from the desander, dewatering of slurry, recycling of fluids, and transport of the collected solids from platform to shore.
Artificial Lift for Slim Holes
Authors: Lea J. F. , Cox J. C. , Adisoemarta P. S. , Nickens H. V.
Published: December 2007

Liquid removal from gas wells is needed as reservoir pressure declines resulting in lower gas flow rates. As liquids accumulate in the wellbore, the hydrostatic pressure due to the liquid column exerts a backpressure on the producing sand face resulting in lower production rates. As additional liquids enter the wellbore, the well will cease to flow. By removing these liquids, gas production is maintained. Since various artificial lift techniques are used to produce these liquids, it is important that the lifting method be compatible with the size of the completions. The purpose of the paper is to discuss which options are available to lift liquids from slim-hole gas wells.
Evaluation of Frac-and-Pack Completions in the Eugene Island
Authors: Fan Y. , Markitell B. N. , Marple B. D. , Valkó P. P.
Published: December 2007

This paper presents a systematic evaluation of frac&pack completions conducted in the Eugene Island region of the Gulf of Mexico. Reservoir, treatment and production data are analyzed from a unified viewpoint. First a completion design strategy is described which is centered around the dual goals of optimal stimulation and sufficient sand control. Then a method is presented to evaluate the technical success of the completion using 3-D reservoir/fracture simulators and the recently developed Slopes Analysis method. Finally, a simple but practical frac&pack treatment design and optimization procedure is presented for improving the performance of frac&pack completions. An example of frac&pack treatment design using the new design philosophy is provided in details showing how to achieve the stimulation goals in a theoretically optimum manner and why often the actual treatment has to depart from the theoretical optimum.
Optimization of Hydraulic Fracturing in a Deep, Multilayered, Gas-Condensate Reservoir
Authors: Langedijk R. A. , Al-Naabi S. , Al-Lawati H. , Pongratz Oman, R. , Elia M. P. , Abdulrab T.
Published: December 2007

Two deep, gas condensate reservoirs are under development in Oman to supply a peak capacity of 40 million m3/d gas for Liquefied Natural Gas (LNG) export and domestic customers. To date (May 2000) 37 multiply-fractured development wells, with a total of 106 hydraulic fracture treatments have been completed in the multi-layered, heterogeneous Barik and Saih Rawl fields.

A continuous optimization process was in place from the beginning to capture all aspects of the project’s learning and reduce development cost. The frac design changes over time as a result of this process will be discussed. Initial well capacity of the wells cleaned up and tested to date is 20% higher than planned, offering considerable project savings.

This paper will describe the way in which the significant challenges in fracturing these deep, multi-layered gas-condensate reservoirs were met.

Difficulties in interpreting and analyzing FETs (Fluid Efficiency Tests) caused by varying stress contrasts in the different layers will be discussed. It will be shown that masking early data of the pressure decline after shutdown in the minifrac can result in misinterpretation of leakoff parameters. Well tests performed at regular intervals gave a better understanding of the optimized relationship between length, width, and height, which in turn led to a revised fracturing design. Perforating strategies influencing the placement of individual fracturing treatments, in particular affecting fracture connected height, will be addressed. Modeling reservoir characteristic has presented significant hurdles with existing fracture simulators, primarily caused by the amount of detail required to accurately predict both the fracturing and productivity behavior in the heterogeneous Barik and Saih Rawl fields.
Mechanistic Model for Upward Two-Phase Flow in Annuli
Authors: Lage Antonio C. V. M. , Time Rune W.
Published: December 2007

A mechanistic model is formulated to predict the mixture behavior for upward two-phase flow in concentric annulus. The model is composed of a procedure for flow pattern prediction and a set of independent mechanistic models for calculating gas fraction and pressure drop in bubble, dispersed bubble, slug and annular flow.

Small-scale experimental data from the literature validate the predictions of the model. A full-scale experimental investigation is also executed to complete the evaluation. The experiments are performed in a 1278 m vertical well in the Petrobras research facility in Taquipe, Brazil, with an 88.9 mm x 159.4 mm (3.5 in. x 6.276 in.) annulus. Test matrix covered the whole range of possible combinations of liquid and gas injection rates for an underbalanced drilling operation in a similar geometry. The overall model performance is in good agreement with the experimental data.
Dynamic Reservoir Characterization at Central Vacuum Unit
Authors: Wehner Scott C. , Raines Michael A. , Davis Thomas L. , Benson Robert D.
Published: December 2007

Multicomponent, time-lapse seismology has great potential for monitoring production processes in reservoirs. The main reason is simply the presence of fluid-filled fractures. Shear waves (s-waves) are much more sensitive than compressional waves (p-waves) to the presence of fractures or microfractures and the fluid content within the fracture network. Fractures introduce seismic anisotropy into a reservoir, causing two shear modes (S1 and S2) to propagate with different velocities and therefore different arrival times. This phenomenon is referred to as s-wave splitting or birefringence, and is critical for estimating fracture density (see Martin and Davis, 1987).

At Central Vacuum Unit (CVU), s-wave splitting is developing as an important key to monitoring production processes associated with carbon dioxide (CO2) flooding. Fluid property changes associated with CO2 flooding produce changes in the velocities of the split s-waves passing through the reservoir interval. Fluid properties change in response to CO2 and oil becoming a miscible phase in the presence of in-situ fluids. S-wave splitting can also be used to identify areas of anomalous reservoir pressure. S-wave splitting and velocities are extremely sensitive to the local stress field because all rocks, especially carbonates, contain incipient networks of microfractures at a state of near-criticality (Zatsepin and Crampin, 1997).

S-wave splitting can assist in separating effective stress changes associated with abnormal fluid pressures from fluid property change. This conclusion is inferred by results of the CVU study. During the first phase, Phase-I of this study, a prominent s-wave splitting anomaly was detected to the south of a cyclic CO2 injection well (CVU 97). It is believed that this anomaly corresponded to the tertiary flood bank that developed south of this temporary injection well (Figure 1a). Noticeable in the periphery to this anomaly are anisotropy anomalies of opposite sign related to offset wells that were used to contain the CO2 bank through water injection. The sign change of s-wave anisotropy occurs because the relative velocities of the split s-waves reverse. In the case of the miscible CO2-oil bank, the S2 velocity increased and S1 decreased, whereas, in the case of water injection, the effective stress causes S2 to decrease and S1 to increase. Similar effects were observed during the second phase, Phase-II of the monitoring study (Figure 1b). These results imply that s-wave anisotropy can be used to monitor secondary (water flooding) as well as tertiary (CO2) methods in a spatial context beyond the wellbore. This dynamic reservoir characterization could provide the industry with the ability to be more proactive than reactive in the management of reservoirs.
Scale Effects on the Application of Saturation-height Functions to Reservoir Petrofacies Units
Authors: Worthington Paul F
Published: December 2007

An internally self-consistent reservoir model has been constructed in order to investigate the effects of scale on the mathematical form and application of four saturation-height functions and thence on the resulting distribution of reservoir fluid saturations. The deterministic treatment uses reservoir partitioning into strongly characterised, but uncorrelatable, physically-distinct litho-units, or petrofacies, for purposes of petrophysical interpretation, and a separate, spatially correlatable reservoir zonation for subsequent parameter mapping and volumetric computations.

The relationship of a petrofacies-specific saturation-height function established at the core-to-log scale to that generated at the reservoir zonal scale varies according to the form of function used and the physical character of the particular petrofacies unit. The deterministic application of diverse functions established at the two different scales has allowed the uncertainties introduced through scale transgression to be compared quantitatively in terms of the predicted zonal water saturations, and thence hydrocarbon saturations, delivered for the parameter mapping stage. The most accurate evaluation of water saturation is provided by an extended algorithm that contains bulk volume water as predictand and was established at the reservoir zonal scale, which has to be used in subsequent volumetric applications. In contrast, an exponential form of saturation-height function is the worst performer, regardless of the scale at which it was established.

The significance and variability of this uncertainty have led to the formulation of a structured approach to the optimum deterministic application of saturation-height functions in integrated reservoir description. Through this facility, it is possible to constrain the uncertainty associated with the distribution of hydrocarbon saturation at the mapping and volumetric stages.
Comparison of Reservoir Simulation Hysteresis Options
Authors: Kossack C. A.
Published: December 2007

An understanding of drainage and imbibition processes, three phase flow models, hysteresis in relative permeabilities and capillary pressure, and scanning curves is vital to the proper use of modern reservoir simulators. Several choices are available to the engineer for the three-phase model, for the hysteresis model, and for the treatment of the wetting phase during hysteresis. The combinations of parameters/models generated by these choices give the engineer a puzzling array of options. Unless one has studied hysteresis and simulated the various cases, it is difficult to know which combination is appropriate for their reservoir.

This paper discusses the models available for hysteresis in water-wet systems and the interaction of these models with the standard three phase relative permeability and capillary pressure models. Simulations are run with various combinations of models and the resulting scanning curves are plotted along with the drainage and imbibition bounding curves. One can see the differences between model combinations. A WAG injection into a linear reservoir is simulated for each combination of options. The oil, gas, and water production rates and oil recovery are compared.

Requirements to obtain proper scanning curves are provided. Experiments are recommended to help the engineer choose the appropriate combination of models for his/her reservoir.
A Coupled Model for Three-Phase Capillary Pressure and Relative Permeability
Authors: Hustad Odd Steve
Published: December 2007

A fully coupled formulation for three-phase capillary pressure and relative permeability is presented. The formulation incorporates hysteresis and miscibility on both capillary pressure and relative permeability, simultaneously. Consistency is ensured for all three two-phase boundary conditions, through the use of two-phase data and the application of normalized saturations.

Simulation examples of Water-Alternating-Gas (WAG) injection are demonstrated using water-, mixed- and oil-wet capillary pressure and relative permeability curves, both exhibiting hysteresis. The examples represent typical core-flooding scales in the cm to m range. Discussions and illustrations are given demonstrating the importance of the functional dependency and the extrapolation of two-phase capillary pressure values to three-phase flow properties.
The Use of Streamline Simulation in Reservoir Management: Methodology and Case Studies
Authors: Lolomari Tony , Bratvedt Kyrre , Crane Martha , Milliken William J. , Tyrie J. J.
Published: December 2007

Because of increased speed and accuracy, 3D streamline simulation now can be used in a wide range of reservoirs. Large reservoirs with hundreds or thousands of wells, several hundred thousand grid blocks and an extensive production history always have been a challenge for finite-difference simulation. The size and complexity of these reservoirs generally have limited simulation to sections or patterns.

The streamline technique enables simulation of these reservoirs by reducing the 3D domain to a series of 1D streamlines along which the fluid flow computations are performed, offering computational benefits orders of magnitude greater.. Additionally, increased accuracy is achieved by maintaining the sharp flood fronts from the displacement processes and reducing grid orientation effects.

The streamline simulation results substantially have more value as a reservoir management tool when used in conjunction with traditional reservoir engineering techniques such as standard finite-difference simulators.

Several case studies that highlight a variety of situations where streamline methods proved highly beneficial are presented in this paper. These studies will help the practicing reservoir engineer decide whether to apply streamline methods and the optimal timing for the application.
Inflow Performance Relationships for Gas Condensates
Authors: Guehria Fawzi M.
Published: December 2007

In this work, we describe a fast scheme to obtain time-dependent IPR curves for a depleting gas-condensate well without resorting to the use of simulation. The model reflects the flowing characteristics inside the reservoir. In addition, it is self-checking and consistent with the overall analysis of gas-condensate reservoir behavior. We also investigate the adequacy of reservoir material balance for gas-condensates to generate the IPR curves for a depleting gas-condensate well.

Transient effects are not considered in this work.

Inflow Performance Relationships (IPR’s) are a critical element in the design of new wells and in the monitoring and optimization of existing producing wells. In addition to Vogel-type relationships, various IPR models for different well geometry and different flow regimes have been presented. Generally, these models take advantage of analytical solutions for single-phase oil and for single-phase gas, to generate a flow rate profile with flowing pressure as a parameter.

For gas-condensate wells, standard dry-gas deliverability equations based on isochronal testing have always been used as IPR models. Unfortunately, due to severe deliverability reduction caused by condensate blockage, this approach is inadequate and usually leads to erroneous results.

In reality, the pressure drop that occurs in gas-condensate reservoirs operating below dew-point, is affected by up to three zones, i.e. 1) inner zone where both phases, gas and free condensate, are flowing, 2) middle zone where two phases coexist but only gas is mobile and 3) outer zone where only the single phase gas is flowing.

We verified the method with synthetic examples and good agreement was achieved in all cases.
Comprehensive System for Treatment and Injection of Produced Water: Field Case
Authors: Mantilla I. , Quintero P.
Published: December 2007

This work describes a comprehensive system that was designed, built and commissioned in Yarigui-Cantagallo field (Colombia) for treating and re-injecting produced water.

The facility mainly consists of one plate-pack separator, one induced-gas flotation cell, one nutshell filter and high-pressure pumps. Field data including water quality analysis in all stages of treatment are shown as well as calculated efficiencies for the equipment.

This system is adequate to obtain high quality water for reinjection in very tight formations.
Volumetric Growth and Hydraulic Conductivity of Naturally Fractured Reservoirs During Hydraulic Fracturing: A Case Study Using Australian Conditions
Authors: Hossain M. M. , Rahman M. K. , Rahman S. S.
Published: December 2007

The limitation of conventional hydraulic fracturing with two long wings of coplanar fractures is well recognized in the context of naturally fractured tight gas or Hot Dry Rock (HDR) geothermal reservoirs. This paper presents a 3D model for an alternative stimulation technology for such reservoirs. The model stochastically simulates actual reservoir representative natural fractures processing field data available from cores and logs. These simulated fractures are then analyzed for deformations with the combination of simple elastic structural mechanics and linear elastic fracture mechanics principles coupling with the injected fluid pressure and in-situ stresses. Finally, the hydraulic conductivity and the reservoir growth pattern are formulated as functions of fracture deformations.

The applicability of the model has been verified using the data of actual fracture stimulation programs conducted in the Hijiori HDR site. It has been found that the model is capable of simulating actual natural fracture distribution in the reservoir. The model is finally applied to a series of numerical analysis with central Australian reservoir conditions to investigate the sensitivity of natural fracture parameters (e.g. size, density and orientation) and in-situ stresses to reservoir growth and conductivity. It is observed that the reservoir growth pattern is mainly influenced by fracture parameters and the relative magnitude and direction of in-situ stresses. Reservoirs with predominantly strike-slip and reverse faulting stress regimes and high deviatoric stresses are favorable for horizontally dominant reservoir growth - a pattern which is highly desirable for efficient HDR geothermal energy extraction. The information provided in the paper is directly applicable to HDR geothermal reservoir development with a high potential for new applications in tight gas reservoirs in which the abundance of natural fractures is so far posing significant complexity to conventional hydraulic fracturing, resulting in multiple fractures, high treatment pressure and premature screen-out.
Interpreting Spinner Response in Multiphase Bubble Flow
Authors: Wang Jianrong , Chace David , Georgi Dan , Maxit Jorge
Published: December 2007

The conventional production logging spinner is widely used to log both single and multiphase flows in producing wells, and it is well known that the spinner response in multiphase flow is complicated and difficult to interpret. A brief literature survey finds few models for interpreting the spinner response in multiphase flow. The general conclusions from previously published works are that the response is still more or less linear with the total volume flow rates, but still very difficult to interpret with any confidence.

In this paper, a mechanistic model based on angular momentum balance of the spinner rotor in bubble flow is introduced. The model is composed of two parts. In the first part, it is assumed that a) the fluids passing through the spinner blades are well mixed, b) there is slip between phases, c) the flow does not swirl. Therefore, an idealized spinner response under idealized bubble flow is developed. The results show that the spinner response in multiphase bubble flow is not a linear univariable function of the total fluid volume passing through the spinner, but rather a multivariable function of slip velocity, volume fraction, continuous phase velocity, and fluid properties. The second part of the analysis introduces the concept of bubble travel length to consider the effect of the spinner cage or centralizer on bubble flow trajectory.
Seismic While Drilling for Enhanced Look-Ahead-of-Bit Capabilities - Case Study of Successful Mud Pulse Coupling Demonstration
Authors: Judzis A. , Green T. S. , Hoversten G. M. , Black A. D.
Published: December 2007

Accurate prediction of formation pressures (pore pressures) is critical to conduct safe and economic drilling operations. This information is essential for both optimizing casing and drilling fluid programs, and is vital in avoiding well control problems. Seismic while drilling techniques offer improved safety and drilling performance for areas where uncertainties exist in formation tops and prediction of over-pressured zones. Examples of potential economic benefit include elimination of casing strings, maintenance of optimum hole size to total depth, and reduction of non-productive time. There are currently no systems that reliably provide this capability.

This paper presents the results of an ongoing development program designed to improve the efficiency and safety of drilling operations through the development of a down hole seismic source for enhanced ‘look-ahead-of-the-bit’ capabilities while drilling. The program is funded in part through the US Department of Energy. Results obtained from innovative large-scale tests show the effects of a down hole seismic source utilizing the hydraulic force of a mud pulse generated through a flow interruption device. Three axis accelerometers embedded in rock samples in a simulated wellbore environment showed signal responses which are under review in anticipation of analyzing ‘look-ahead-of-bit’ requirements.

The results provide a unique opportunity to examine seismic wave propagation in samples shorter than a wavelength and the potential to benchmark seismic sources for coupling efficiency before deploying tools in an expensive offshore environment. For offshore operations, the ability to improve pore pressure predictions ahead of the bit is one key to success.
Enhanced Productivity in a Heavy Oil Reefal Reservoir as a Result of Improved Reservoir Characterization
Authors: Elshahawi Hani , Klimentos Theodore , Elzefzaf Taher , Emara Maher
Published: December 2007

The Nullipore reservoir in the fields of Egypt's General Petroleum Company (GPC) is a heavy oil reefal reservoir located in the Gulf of Suez area. The Nullipore formation is characterized by a high degree of heterogeneity, which, in addition to the high oil viscosity, has made it difficult to locate and drain oil effectively. This was further complicated by the lack of accurate seismic and geological data. For these reasons, the reservoir had been traditionally considered only as a secondary or backup prospect. Recently, an approach was initiated, based on the use of innovative logging techniques for better reservoir characterization as well as production data analysis for better understanding of reservoir dynamics. This has led to the realization that the reservoir's productivity is primarily controlled by the flow contribution from natural fractures. New horizontal wells were hence planned and completed on the basis of the newly acquired information with excellent results. Moreover, older wells were recompleted using the data acquired from these horizontal wells, leading to large increases in production.

This paper describes the methods used to locate the natural fractures that lead to the majority of production in the Nullipore reservoir. Central to these are the fracture detection logs and log-analysis methods employed. It also details how new wells can be put in place to intercept these fractures and effectively drain the oil.
Remaining Oil Saturation from NMR in a Mixed-Wet, Three-Phase Carbonate Reservoir
Authors: Akkurt R. , Merkel R. H. , Coates G. R. , Stever R. C.
Published: December 2007

Accurate determination of remaining oil saturation is critical for the successful implementation of enhanced recovery programs planned for the Yates field. Determination of oil saturation in this strongly heterogeneous, mixed-wet, and vuggy carbonate reservoir, however, is difficult. Conventional methods generally fail to produce robust results because of the variations in the Archie exponents m, and n, both in space and time. The saturation variations originate from the double displacement processes employed for improved recovery, which have generated a sizable gas cap and a moving oil/water contact.

Because of its direct reservoir fluid characterization capabilities, NMR logging was earlier identified as a potential alternative for the direct determination of remaining oil saturation at the Yates Field. A series of MRIL logs was run in 1998, where the main objective of the logging program was to exploit the diffusion contrast between oil and water. Results from this logging program were unsatisfactory because the apparent T2 contrast between the oil and water phases was not sufficiently large to allow an accurate determination of the various fluid fractions.

An extensive modeling study was then initiated to study the feasibility of NMR logging for oil saturation measurements. Existing MRIL logs and limited laboratory data were used as input into the models. Modeling showed that interecho times in excess of 6 ms. could increase the apparent T2 contrast between the oil and water phases. However, modeling also showed that such an increase in T2 contrast would be accompanied by severely lowered T2 resolution, which would in turn increase the uncertainty in computed saturations. Further modeling showed that the combination of higher magnetic field gradients and long interecho times could yield sufficient T2 contrast without compromising T2 resolution. It was then decided to modify an existing MRIL-C tool to achieve these objectives.

An observation well that was included in the 1998 program was relogged in late 1999 with the specially configured MRIL-C tool. Interpretation of the data acquired with this special tool and the remaining oil saturation determined from an NMR only technique agreed very well with the existing field model and petrophysical data. Expansion of the pilot study to a multiple-well evaluation program is currently being planned.
The Dynamics of Combustion Fronts in Porous Media
Authors: Akkutlu I. Yücel , Yortsos Yannis C.
Published: December 2007

The sustained propagation of combustion fronts in porous media is a necessary condition for the success of an in-situ combustion project for oil recovery. Compared to other recovery methods, in-situ combustion involves the added complexity of exothermic chemical reactions and temperature-dependent chemical kinetics. This gives rise to reaction zones of a spatially narrow width, within which heat release rates, temperatures and species concentrations vary significantly. This sharp variation makes difficult the simulation of combustion processes using coarse grids and the implementation of upscaling methods.

In this paper, we propose a method for solving this problem by treating the reaction region as a place of discontinuities in the appropriate variables, which include, for example, fluxes of heat and mass. Using a rigorous perturbation approach, similar to that used in the propagation of flames [3], and smoldering combustion [7], we derive appropriate jump conditions that relate the change in these variables across the front. These conditions account for the kinetics of the reaction between the oxidant and the fuel, the changes in the morphology of the pore space and the heat and mass transfer in the reaction zone. Then, the modeling of the problem reduces to the modeling of the dynamics of a combustion front, on the regions of either side of which transport of momentum (fluids), heat and mass, but not chemical reactions, must be considered. Properties of the two regions are coupled using the derived jump conditions. This methodology allows to explicitly incorporate permeability heterogeneity effects in the process description, without the undue complexity of the coupled chemical reactions.
Oxidation of Heavy Oil and Their SARA Fractions: Its Role in Modeling In-Situ Combustion
Authors: Akin Serhat , Kok Mustafa V. , Bagci Suat , Karacan Ozgen
Published: December 2007

In situ combustion is a thermal recovery technique where energy is generated by a combustion front that is propagated along the reservoir by air injection. Most of the previously conducted studies report thermal and fluid dynamics aspects of the process. Modeling in situ combustion process requires extensive knowledge of reservoir data as well as reaction kinetics data. Unfortunately, limited kinetic data are available on the rates and the nature of partial oxidation reactions and the high-temperature combustion reactions of crude oils and their saturate, aromatic, resin, and asphaltene (SARA) fractions. Moreover, the impact of such data on the modeling of the in situ combustion process has not been investigated thoroughly. Thus, we modeled in situ combustion experiments conducted on a 3D semi-scaled physical model that represents one fourth of a repeated five spot pattern. In all experiments a vertical injector is employed whereas, both vertical and horizontal producers have been installed to recover two different crude oils (heavy and medium). Several locations for the producers have been tried while keeping the length of the wells constant: vertical injector-vertical producer, vertical injector-horizontal side producer, and vertical injector-horizontal diagonal producer. In these experiments diagonal producers performed better than the others. We first simulated the experiments by incorporating a kinetic model that is based on grouping the products of cracking into six pseudo components as heavy oil, medium oil, light oil, two non-condensable gases and coke using a commercial thermal simulator (CMG’s STARS). Four chemical reactions were considered: cracking of heavy oil to light oil and coke, heavy oil burning, light oil burning, and coke burning. Most of the experiments were history matched successfully with the exception of ones where a diagonal horizontal producer was used. We then repeated the simulations using SARA kinetic parameters. We observed that all matches were somewhat improved. We finally present a discussion of application of the models to field scale.
Filtercake Cleanup in Open-Hole Gravel-Packed Completions: A Necessity or a Myth?
Authors: Brady M. E. , Bradbury A. J. , Sehgal G. , Brand F. , Ali S. A. , Bennett C. L. , Gilchrist J. M. , Troncoso J. , Price-Smith C. , Foxenberg W. E. , Parlar M.
Published: December 2007

Offshore reservoirs requiring sand control pose a major completion challenge because of extremely high cost and risk involved in remedial treatments, particularly in sub-sea completion and/or deep-water environments. It is therefore of utmost importance to ensure sand control without sacrificing flow conformance, recoverable reserves and well deliverability throughout the expected life of the completion. A major trend in these environments is towards open-hole, horizontal, gravel-packed completions. Although gravel packing stabilizes the wellbore, it can also entrap the filter-cake formed by the reservoir drilling fluid, potentially resulting in high drawdown requirements (flow initiation pressures) and/or low production rates (retained permeabilities). The cleanup procedures in the industry have varied significantly from no cleanup at all to complicated two-stage breaker treatments involving post-completion coiled tubing intervention, with no guidelines existing in the literature.

In this paper, we present experimental results and field cases involving filter-cake flow-back through gravel packs with and without cleanup. Effects of various parameters, including gravel size (40/60, 20/40, and 12/20), formation permeability, drill-solids type (clays, quartz) and concentration, and the type of cleanup fluid have been investigated. Flow initiation pressure and retained permeabilities during flow back are reported as a function of these parameters. The experimental results show that the flow initiation pressure is a strong function of gravel size and the type of drill solids. It is concluded that, in clean (low-to-no clay content) formations of large grains and high permeabilities (~ several darcies) requiring large gravel sizes (e.g., 12/20), an enzyme or an oxidizer treatment is sufficient based on laboratory results and productivity predictions. This conclusion is also supported by several field applications as shown. In lower permeability (~ 100–250 md) formations of small sand sizes requiring smaller gravel (e.g., 40/60) elimination of both the fluid loss control agent (starch) and bridging agent (CaCO3) is necessary based on high flow initiation pressures and low retained permeabilities. In intermediate permeability (~ 500–800 md) formations of medium size sand-grains typically requiring 20/40 gravel, the results depend strongly on the type of drill solids: in clean formations (no clays in drilling fluid), an enzyme or an oxidizer treatment is sufficient, while in dirty formations removal of both CaCO3 and starch is necessary. These results are also supported by field case histories presented in the paper.
Outside Gravel-Pack Optimization, Based on Hydraulic Fractures Done in Gelatin
Authors: Stockhausen H. W. , Logan J. M. , Montgomery C. T.
Published: December 2007

This study use gelatin as an inexpensive physical model material to simulate poorly consolidated sediments and investigated selected problems associated with hydraulic fractures, in the sense of find ways to surround a vertical well with hydraulic fractures and extend selected ones into the formation as wing fractures in two different stress environments.

A technique was developed to control initial hydrofrac orientation based on tensile strength, fluid inertia, and breakdown pressure, which combine with an appropriate shooting phase oriented respect to the field stresses enable surround a well and form wing fractures to set an outside gravel pack.

The results of theses experiments were used to improve the novel technique of outside gravel pack as an economical alternative to enhance hydrocarbon productivity.
How Can Sand Production Yield a Several-Fold Increase in Productivity: Experimental and Field Data
Authors: Vaziri H. H. , Lemoine E. , Palmer I. D. , McLennan J. , Islam R.
Published: December 2007

Centrifuge physical model tests were performed to study the mode of failure during sand production and its concomitant impact on the productivity index. The tests simulated seepage-induced failure around a vertical well. Results indicate that in the presence of a competent cap rock (1) sand production results in the formation of a cone-shaped enlarged cavity; (2) surface subsidence of the reservoir due to loss of sand mass which may result in opening of flow channels under the cap rock; (3) for a given wellbore pressure, sand production ceases once the enlarged cavity lowers the flowrate to sub-critical level; (4) flow becomes diverted towards the upper perfs where the cavity radius is largest; (5) flow rate increase varies between 5 to 50 times depending on whether the mode and volume of sanding is sufficient to result in the formation of flow channels. The study performed shows that (1) the location of perfs affects the mode and magnitude of sand production and the concomitant productivity, and (2) long-term productivity can be improved through managed sand production. Presence of a competent cap rock is the key for maximizing the productivity via sanding. These findings are consistent with some field cases where extraordinary increases in production were noted as a result of sanding. Sand production, if properly managed, can reduce the completion costs (e.g., by omitting or delaying installation of sand exclusion measures) and improve the long term productivity by removing the skin damage and also through creating voids and zones of higher porosity around the well and under the caprock.