bluuebunny/crossref_metadata_2025 huggingface dataset:
Microseismic Monitoring of a Restimulation Treatment to a Permian Basin San Andres Dolomite Horizontal Well
Authors: Quirein J. A. , Kessler C. , Trela J. M. , Zannoni S. , Cornish B. , Brewer R. J. , Gordy D. , Pettitt W. S. , Walker C. B. , Laney J. , Young R. P.
Published: December 2007

The results of a microseismic monitoring of a multi-stage refracturing treatment of a Permian Basin San Andres dolomite interval in an open-hole horizontal well will be presented in this paper. The treatment well has a horizontal well trajectory of approximately 3,000 feet within the reservoir section and had been extensively acid fractured during earlier production enhancement operations. The microseismic mapping objectives of the re-fracturing treatment for each of the stages were to characterize the azimuthal orientation of the fractures, the length of each wing, fracture height, and overall stimulation effectiveness.

The study discusses mapping microseismic events in a challenging re-fracturing environment. The microseismic activities generated during a re-fracturing treatment may be very low in acoustic energy and detection may be problematic, compared to the acoustic energy released during initial hydraulic fracture propagation. In this study, few microseismic events were detected, and this data indicates that the previously propagated fractures created preferential paths for fluid flow thus reducing the propagation of a new fracture network. In fact, for the stage located the furthest from the monitor well, no microseismic events were detected. This was consistent with an Instrument Magnitude Analysis performed on the located microseismic events from the other stages that showed events further than 1,400 feet away from the monitor well were not detectable.

A chemical packer was used for zonal isolation, and ball- activated sliding sleeves were used for selective injectivity for each stage along the horizontal well in the re-fracturing treatment. The operation of the sliding sleeves, for each stage and the ball drops, generated compressional and shear events which were detected by the geophone array in the monitor well. This confirmed that the instrumentation was able to detect events between the treatment well and monitor well in this job and that the microsesimic events induced during the re-stimulation treatment were at a much lower energy. The low-energy events that were located confirmed the ball- activated sleeve worked correctly and the induced fractures stayed in zone. However, the source locations detected did not delineate clear linear propagation of hydrofractures from the wellbore but described a complex fracture network.
Combining Advanced Real-Time LWD Answers with Accurate and Flexible 3D Rotary-Steerable System for Proactive Reservoir Navigation
Authors: Gravem Trond , Berle Alf , Gundersen Sven S. , Pedersen Jarle , Rorvik Kjell Oddvar , Hansen Atle
Published: December 2007

Development of formation evaluation technologies for azimuthal, deep-reading measurements and accurate and flexible 3D rotary steerable drilling systems have made it possible to provide truly proactive well placement. Real time use of new and advanced LWD data in horizontal drilling gives the opportunity to extend the envelope for well planning and reservoir information gathered in a single run. Optimum interpretation from real time data acquisition facilitates a reformation of the way horizontal wells are planned and drilled. This paper shows a well where the information was extracted and included in the decision making process to an extent that sets a new industry standard. Applying an accurate 3D rotary steerable system with openhole sidetrack capabilities increase well design flexibility and the ability to act on the real-time LWD data. The bottom hole assembly used consisted not only the standard LWD services such as gamma ray, propagation resistivity, density, neutron porosity and LWD gamma ray and density imaging services, but also formation pressure testing while drilling and the newly introduced azimuthal propagation resistivity. The azimuthal propagation resistivity provides unique information of the approaching bed and fluid contacts. Verification or change of the geological model during drilling through comprehensive use of forward resistivity modeling and real-time geological interpretation based on both the newly introduced azimuthal propagation resistivity service and resistivity from multiple depths of detection as well as wellbore images from both density and gamma ray, give a solid and enhanced base for real time well placement in horizontal drilling. The horizontal interpretation of resistivity data together with structural interpretation of image data gives an unmatched understanding of the geology and aids in placing the well better. Horizontal real time wellbore placement is then accompanied by real time reservoir characterization through real time formation pressure measurement to validate any fluid movements and fluid compartmentalization of the reservoir. This paper is based on wells drilled in a chalk field in the North Sea where real time data acquisition plays a significant part and illustrates to what level LWD data can facilitate proactive well placement and comprehensive reservoir characterization.
Analysis of Well-Test Data in a Multiwell Reservoir with Water Injection
Authors: Lin Jia-En , Yang Hui-Zhu
Published: December 2007

In this paper, a general method has been developed by taking into account the production time for analyzing the pressure buildup or falloff data from a well located in a bounded homogeneous rectangular reservoir, with an arbitrary number of both production and injection wells. In the new solution, injection-production ratio (IPR) was introduced to measure the regional strength of fluid injection or well interference. The previous solution developed by Marhaendrajana et al (1999) is a special case of this new solution.

For the analysis of well test data from a well in multiwell reservoir where both production and injection wells exist, we treat the "well interference" effect as a "regional reservoir pressure trend". We use a diagnostic plot comprising the pressure change and pressure derivative calculated with respect to, and graphed vs., equivalent time to recognize the interference of offset wells. For oil/water systems, we assume that saturation gradients are negligible in the drainage area of the tested well. The proposed method enables one to calculate the total mobility or permeability-thickness product and the skin factor with accuracy from pressure buildup (or falloff) data dominated by regional reservoir pressure trend.

A field example has been presented to illustrate the validity and applicability of the proposed method. The significant new contribution of this work is the development of the new multi-well solution by taking into account well interference effects from both production and injection well.
Subsea Slimhole Completions in Deepwater Gulf of Mexico: Case Histories
Authors: Sanford J. R. , Cordeddu C. , Edwards W. J. , Baccigalopi G. D.
Published: December 2007

Typically, deepwater subsea completions are characterized by significant production rates which require large completion hardware. Slim-hole designs (defined as 5½" production casing and smaller) are usually avoided due to increased risk and production concerns.

However, as the deepwater Gulf of Mexico basins grow more mature, sidetracks and challenging new drills become frequent. Sidetracks out of 7¾" to 7" production casing are being performed, ending with 5½" or 5" casing at TD. Additionally, many new drills either have to penetrate multiple depleted intervals or require more aggressive directional plans to reach smaller targets. Both scenarios can result in slim-hole designs.

Historically, the two (2) riskiest phases of the completion are wellbore displacement and sand control. This paper presents the design, the risk assessment, the installation and the actual results for three (3) subsea slim-hole deepwater completions. A summary of the completions are as follows: 5" Frac Pack (FP) at 74 degrees deviation5" FP with > 40000 md-ft kH sand5½" High Rate Water Pack (HRWP) at 25000 ft TVD

As a result of proper planning, the Case Histories were successfully executed in Gulf of Mexico deepwater. However, performance expectations from these type wells must be risked and managed.
The Development of World-Class High Rates, High Ultimate Recovery Wells in Deepwater Turbidites—Bonga Field, Offshore Nigeria
Authors: Inikori Solomon O. , Spring Laurent , Ageh Ebenezer , Van der Bok Jaap
Published: December 2007

Bonga field in deepwater Nigeria produces hydrocarbons from classic deepwater turbidites reservoirs in channel settings. The reservoirs consist of series of amalgamated channel complexes with varying degrees of compartmentalization. This configuration presents significant uncertainties in connected volumes, well placements and sweep efficiency between water injector/producer well pairs. However, due to the high costs of deepwater developments, well count needs to be as low as practical, and production rates must be sustainably high to ensure economic robustness of the project. High rates and high ultimate recoveries are the foundations of successful deepwater projects, where constant pressure maintenance is a key component. Several research studies conducted recommended that water injection wells be designed for fractured injection in order to sustain the required high rates as opposed to matrix injection. This paper presents the results of these research efforts leading to this conclusion and the implications on reservoir management.

Also presented is an overview of the challenges of developing these complex channel deposits as well as the new approach to modeling of high rate wells in deepwater turbidites.

Key to a successful understanding of reservoir behaviour (connectivity) and early indications of future reservoir performance is through a systematic undertaking of interference tests at production start-up.

After about 2 years of production, the results from the Bonga wells demonstrate that sustained high oil rates could be achieved with adequate pressure maintenance. Average oil production rates of vertical/deviated wells range between 15,000 to 22,000 bopd and that of horizontal wells range between 25,000 to 35,000 bopd. Estimated Ultimate recovery (EUR) range from 20 to 100 mmstb for phase 1wells and from 10 to 30 mmstb for phase 11 development wells with several opportunities for infill drilling of low EUR wells. Nameplate capacity of 225,000 bopd is achieved and sustained with just 9 producers and 6 injectors. In order to maintain reservoir pressures from these high uplift rates, world-class water injection rates of between 40,000 to 70,000 bbls per day per well have been sustained since first oil.

The fracture injection approach is applicable both for onshore and offshore reservoir development but more significantly for deepwater reservoir development where sustained high rates and economic considerations are paramount.
Improved Drilling Performance in Lake Maracaibo Using a Low-Salinity, High-Performance Water-Based Drilling Fluid
Authors: Montilva Julio , Van Oort Eric , Brahim Ricardo , Luzardo Juan Pablo , McDonald Mike , Quintero Lirio , Dye Billy , Trenery John
Published: December 2007

Improved drilling techniques have overcome many of the inherent difficulties associated with the delivery of Icotea and Misoa wells in the West Urdaneta Field of Lake Maracaibo. Advancements such as rotary steerable assemblies, logging-while- drilling (LWD) tools, annular pressure subs and new bit designs have allowed drilling of extended reach and horizontal wells to become routine. However, borehole instability and lost circulation problems have continued to negatively impact operations, compounding well delivery costs.

In an effort to address these problems, a variety of non-aqueous fluids (NAF) and water-based muds (WBM) have been used. While each provides distinct advantages, there has never been a system which could solve all problems associated with drilling the Icotea and Misoa formations. Lost circulation and wellbore instability (defined by almost continual caving of shales in the La Rosa formation) have plagued NAF applications in this field. A variety of WBM systems have been used and each one has also presented its own problems including hole enlargement, bit balling, accretion, low rates of penetration, insufficient hole cleaning, and the need for excessive backreaming.

Finding a fluid that would deliver step-change performance in of drilling efficiency compared to previously used systems, while also adhering to the strict environmental limitations for the area, was paramount to continue economically viable drilling operations in the Urdaneta Field. This challenge was met using an environmentally benign, low-salinity high-performance water-based mud (HPWBM), which was field tested in the intermediate section of the Icotea and Misoa wells. The novel fluid was used to drill through the problematic Laguna, Lagunillas, and La Rosa formations.

By analyzing the field tests results, conducting after action reviews (AAR) and maintaining a productive dialogue between all parties involved, the operational performance of these wells showed substantial and continual improvement. The low-salinity HPWBM is now our system of choice for drilling intermediate hole sections in the West Urdaneta Field.

This paper provides a detailed technical overview of the new HPWBM, provides and the results of the early field tests and of subsequent wells, demonstrates enabling impact of this new technology on driving continual operational improvement.
Operation Centres, Realtime Data and Data Management. Quo Vadis?
Authors: Grøvik Lars Olav
Published: December 2007

This presentation is about some of Hydro's experiences with the digital-oilfield. Main topic is Data and Data-management issues related to: Operation-centresRealtime-dataInformation-technology (changing software etc)

It is NOT a presentation of the "perfect" Hydro solution, since it is not perfect (yet)……

I want discussion and cooperation, allowing us to solve mutual problems and challenges.
Construction of a Stochastic Geological Model Constrained by High-Resolution 3D Seismic Data—Application to the Girassol Field, Offshore Angola
Authors: Lerat O. , Nivlet P. , Doligez B. , Lucet N. , Roggero F. , Berthet P. , Lefeuvre F. , Vittori J.
Published: December 2007

This paper presents a specific workflow developed to build a detailed geological model constrained by high-resolution 3D seismic data. The objective of the proposed approach was 1/ to integrate both geological and seismic information in a coherent fine-grid model at early stage of field production, 2/ to account for uncertainties in heterogeneity distribution, and 3/ to prepare the integration of 4D seismic data.

The first and critical step of this approach was the definition of a 3D grid of facies proportions from 3D HR seismic data to constrain the geological modeling process. A novel approach has been developed to account for scale differences between seismic and well data to obtain a detailed geological facies description.

In the second step, geological facies proportions derived from the seismic facies characterization have been optimized to minimize the differences between the seismic impedances of the average stochastic model and the real impedances.

In the last step, the truncated Gaussian algorithm has been used to generate stochastic realizations constrained by well data and geological facies distribution. Multiple realizations have been used to quantify uncertainty on facies spatial distribution.

This approach was applied successfully to the Girassol field, a complex and faulted turbidite field located offshore Angola. The objective was to build an initial geological model for an innovative history matching workflow integrating 4D seismic data (Roggero et al., [1]).

Thanks to the exceptionally high resolution of the seismic data, a 3D matrix of lithofacies proportions has been constructed with a resolution close to that of standard well logs (metric). Together with variograms, these geostatistical parameters have been used to generate equiprobable images of the geological model. Both well data and the seismic constraint are honored. Average sand proportions and volumes computed from ten realizations are in good agreement with the average values computed using the seismic constraint. Variability in the distribution of geological facies has been quantified and can be related to the uncertainty of the seismic constraint. This uncertainty has been reduced in the history matching process by introducing more deterministic geological information.
Field Implementation of Gravel Packing Horizontal Wells Using a Solids-Free Synthetic Fluid With Alpha/Beta Wave Technology
Authors: Aragão A. F. L. , Calderon A. , Lomba R. F. T. , Moreira J. N. V. C. , de Sá A. N. , Martins A. L. , Quintero L. , Moura E.
Published: December 2007

This article details the planning and execution phases of the first open hole gravel pack operation performed whith the alpha beta wave deposition technique using a non aqueous system as a carrier fluid. The operation was performed at Marlim Field, offshore Brazil, and constitutes the first field implementation of a research and engineering effort which started two years ago.

The idea in this first field operation was to avoid many changes in the original well design for the area and to concentrate novel steps in the fluid for gravel packing openhole design, friction loss evaluation, fluid substitution and rheology characterization are some of the new aspects detailed for the fluid design. Based on these results, optimized procedures were proposed for the operation. A broad description of the technical aspects, field pumping profiles and packing quality is also presented.
Stress-Dependent Permeabilities of Sandstones and Carbonates: Compression Experiments and Pore Network Modeling
Authors: Dautriat J. , Gland N. , Youssef S. , Rosenberg E. , Bekri S.
Published: December 2007

Mechanical effects are of great importance during reservoir production and induce sensible changes of the transport properties. This work focuses on the forecast of the change of porosity and permeabilities of reservoir rocks submitted to hydrostatic and deviatoric stress states representative of the field conditions. To predict these evolutions, we need to perform flow experiments with representative stress conditions. Our triaxial cell was designed to achieve this purpose and allows the measurement of permeabilities in the directions along and transverse to the principal direction of stresses. A good knowledge of the rock microstructures is also fundamental to choose the correct set of parameters for the simulation tools, and the input from our micro scanner facility is therefore of great importance. Using our directional permeability triaxial apparatus, we applied different stress paths to sandstones and carbonates samples and the evolutions of porosity and permeabilities were monitored during loading. We performed a microstructural analysis of these rocks using Mercury Porosimetry and Computed Micro Tomography imaging. From the 3D reconstructions, we extracted the poral network skeletons and the associated pore and throat size distributions. Then we performed two kinds of pore network modeling, one based on the real pore geometry and another based on a statistical description, to calculate the macroscopic transport properties. We included a model of pressure dependence of pore and throat sizes, based on deformation of porous inclusions in the framework of elasticity theory, to simulate the evolution of the transport properties with pressure. This model requires the knowledge of the elastic moduli of the rocks which were determined experimentally from the compression experiments. We show that the experimental determination of the evolution of directional permeabilities under hydrostatic and deviatoric stress conditions is feasible. The pressure dependences can be of valuable importance and therefore influence of mechanical effects should be investigated in experimental transport studies. Finally, we show that pore network modeling associated with CMT imaging can be used to forecast the pressure evolution of transport properties and therefore to understand the reservoir response to production.
Gas Bubble Nucleation of Extra-Heavy Oils in Porous Media: A New Computerized Tomography Technique and Physical Approach
Authors: Meyer V. , Pilliez J. , Creux P. , Graciaa A. , Luck F. , Franco F. , Mauduit D. , Montel F.
Published: December 2007

The study of multiphase flow pore level physic has scientific appeal as well as many applications, mainly in oil reservoir engineering. In this work, we show that micro-tomography is an effective tool to extract the structure of many solid systems in a non-destructive and classical manner. Recently, X-ray computed tomography tools have been extended to the ability to contrast fluids in the pore space of core samples.

As time required for collecting a CT image is much longer than almost flow time scales, CT imaging must occur at static flow conditions to accurate geometrical information on fluid-fluid and solid – fluid interaction.

Considering new decisive developments of the visualization cell we claim to have developed a new petrophysical tool which might permit to access experimentally to the visualization in quasi-static flow of the capillary phenomena and multiphase flows analysis in 3D form or in dynamic flow in 2D form. The in-situ measurements are realized in reservoir conditions of extra-heavy oils.

The aim of the measurements is first to contribute to a predictive bubble population balance which will then be integrated in a network flow model computation. This step is required to develop physical models to obtain a more efficient reservoir simulation. More precisely we focus our attention on a quasi static model of bubble nucleation which appears decisive and we demonstrate how to simulate the whole bubble nucleation and the corresponding experimental results to corroborate the experimental observations. We focus here on the influence of the gas availability in the porous media (diffusivity, GOR or porous media morphology).
World's First Metal PCP SAGD Field Test Shows Promising Artificial-Lift Technology for Heavy-Oil Hot Production: Joslyn Field Case
Authors: Beauquin Jean-Louis , Ndinemenu Felix , Chalier Gilles , Lemay Lionel , Seince Laurent , Damnjanovic Alex
Published: December 2007

Finding a reliable artificial lift pumping system for heavy oil thermal recovery has been a challenge mainly due to the high operating temperatures (>150°C). Available options such as Rod Pumps and Electrical Submersible Pumps (ESP), which are well proven in the industry, are not particularly well suited to thermal production. While Rod Pumps offer high temperature service, they are limited in the flowrate they can deliver. ESPs on the other hand, can handle high volumes of low viscosity fluids, but are still limited in terms of maximum operating temperature.

Progressing Cavity Pumps (PCP), with elastomeric stator, is economic to run and have done well in heavy oil cold production. These elastomers are however limited in temperature (<150°C). Through research work conducted by PCM and TOTAL, Metal PCP technology has been developed to meet the high temperature requirement of SAGD and other thermal recovery processes. Three models of the Metal PCP are now available to cover a wide range of flow rates for heavy oil production.

This paper presents an update on the Metal PCP development and the results of the world's first SAGD field trial of this type of pump currently on-going in Canada in the Joslyn field. Field performance data are discussed comparing high temperature ESP and metal PCP in actual LP-SAGD conditions.

Four SAGD well pairs were initially equipped with high temperature ESP. Another well pair was equipped with metal PCP. This well has been running since mid October 2006 without problems, in spite of low pressure at pump intake, close to steam flashing conditions. Production rate reached 200m3/d of liquid at 340rpm, giving a volumetric efficiency of 53%. Intake temperature is 160°C due to the LP-SAGD condition of the field. However, this pump is rated up to 350°C.

This first field trial shows the metal PCP as a promising artificial lift technology for hot production. Following this encouraging trial, a second metal PCP has been installed with success in the same field and more installations were decided eventually. Thus, all ESP initially installed were replaced by PCP and nine wells are producing with Metal PCPs currently.
Concept and Development of a Flow System for Handling and Exporting 600,000 bbl/day in Campos Basin, Brazil
Authors: Bordieri Eduardo , Vianna Cláudio Siqueira , Vidal José Oliveira
Published: December 2007

Considering demands for internal Brazilian market and international crude oil trade, PETROBRAS has taken the decision to concentrate a significantly part of the future of crude oil production from three deep-water fields; Roncador, Marlim Sul and Marlim Leste, all of which are in Campos Basin, with one off-shore terminal. The name of this project is PDET.

This project comprises of a fixed central pumping station, PRA-1, a large FSO (2,1 million barrels storage capacity), and two calm buoys systems, at a depth of 100 m.

The start-up of this project involves the crude oil from three producing platform; P-52, P-51 and P-53, which are all currently under advanced construction. In the future PDET will receive the production of crude oil from two additional new platforms.

Each producing platform will have its own export pipeline, direct to PRA-1. The peak production of this system will achieve 600,000 bbl/day. PRA-1 will have special requirements to pump crude oil either to FSO or to the calm buoys systems. Based on a steel jacket structure the capacity of power generation will be 75 MW, up to 34 inches pigging capacity and many diverse pipings.

The FSO has special specifications such as the electrical power and optical swivels, both are at a high level of technology and capacity. To achieve system's targeted reliability extensive studies were done. Integrity protection system, leak detection system, offloading time, sub-sea layout and flow rates were taken into consideration. Environmental risks were fully mitigated. The final configuration, which achieved high standard integrity assurance, produced a valuable project.

This paper describes the logistics of this project focusing PRA-1 pumping, the export system through calm buyos, sub-sea facilities and the FSO. Also it will be highlighted some management programs used to implement this project. This work reviewed the major aspects of implementing this important infrastructure offshore facility to transport crude oil.

Several technical and managerial challenges were surpassed through introduction of new technologies, tools and techniques.
Challenges Associated With Subsalt Tar in the Mad Dog Field
Authors: Romo Louis A. , Prewett Harry , Shaughnessy John , Lisle Ed , Banerjee Sanjay , Willson Stephen
Published: December 2007

The Mad Dog field is located in Southern Green Canyon approximately 150-miles south of New Orleans, in 4400-ft to 6800-ft of water (Figure 1). Mad Dog wells are sub-salt and are drilled to the Lower Miocene at approximately 19000-ft true vertical depth (tvd). The discovery well for the field was drilled in 1998. Drilling in the field has been challenged by "mobile" tar. Tar has been encountered in other deepwater fields; however, other reported tar deposits have not had the mobility of the tar encountered in the Mad Dog area

Extensive work has been conducted in developing the Mad Dog tar mitigation plan and has included characterization of tar, laboratory plunger experiments with Mad Dog tar, tar shoe design optimization, investigation of solvents and catalysts to solidify tar, investigation of downhole pyrotechnic heating, investigation of coating agents and the review of drilling practices. This paper will document the theory on the origin of the tar deposits, steps taken to deal with the tar and experience with the tar.
The Intrinsic Reliability of Manometric Sorption Apparatus Using Supercritical Carbon Dioxide
Authors: van Hemert P. , Wolf K-H. A. A. , Bruining J.
Published: December 2007

The sorption of CO2 on coal is of great interest when investigating the possibility of CO2 Enhanced Coalbed Methane or sequestration of CO2 in coal. The measurement of accurate supercritical CO2 sorption isotherms has proven to be a complicated matter. Therefore, a high accuracy manometric apparatus has been constructed and the reliability of the setup itself is thoroughly investigated. Experimental errors are categorized according to the source of the error, instead of the classical categorization of random and systematic errors. These sources are: (1) Background theory fallacies, (2) effects of minor importance, (3) observational errors and (4) interpretational errors.

The reliability of the set-up is investigated by examining the errors of the volume ratio measurements. Volume ratio measurements are sorption measurements, but simplified by not using a sample and without the cumulative effect of errors in sorption measurements. The volume ratio stems from a material balance and the expansion of gas from one cell to another. The pressure and temperature of both cells are measured before and after expansion. The density is calculated from the pressure and temperature with an Equation of State, which also must be of high accuracy.

The accuracy of volume ratios measured with helium and carbon dioxide is investigated. Helium measurements are the base case that demonstrates optimal measurement accuracy. The observed errors in the experiments with helium correspond to the a priori error estimation (σ ≤ 0.2%). The difficulty with CO2 measurements is identified as the high sensitivity of the CO2 density for changes in pressure, temperature and impurities in the 80-120 bar region at 318 K. The high accuracy manometric apparatus can measure CO2 volume ratios with an uncertainty of less than 2%, except between 90 and 110 bar where the uncertainty is less than 10%. This larger uncertainty is caused by impurities in the CO2 of unknown origin. The influence of leakage, changes in the cell volumes, water desorption from steel and the influx of contaminants are shown to be of negligible influence. The error assessment in this paper will serve as the basis of uncertainty analysis of future high accuracy CO2 sorption measurements.
Impact of Self-Consistent Physically-Based Three-Phase Relative Permeability on Oil Recovery by Secondary Gas-flooding
Authors: Alamdari Baharak Barzegar , LaForce Tara , Piri Mohammad
Published: December 2007

We use a three-dimensional random pore-scale network model to simulate gas injection into oil and water after primary drainage. The model is based on the physics of multiphase flow observed in micromodel experiments. Important features of immiscible fluid flow at the pore scale, such as wetting and spreading layers and wettability alteration are implemented. The pore network simulator is utilized to model relative permeabilities, saturation paths, and capillary pressures. A random network that represents the pore space in Berea sandstone is used in this study. Three-phase relative permeabilities generated by the network model are dependent on the saturation path, which is not known a priori.

This paper includes numerical and analytical solutions for a series of secondary gas-floods with relative permeabilities generated using the network model. Analytical and simulated solutions such as these illuminate the large impact of correctly accounting for the effects of saturation history in relative permeabilities in gas injection. This knowledge is critical for the design of EOR schemes such as tertiary gas injection and WAG flooding. It is demonstrated that saturation history has a substantial impact on the relative permeabilities, and hence oil recovery. For the examples studied here, the physically-based relative permeabilities with correct saturation history exhibit an extremely rare solution structure. This is a strong indication that many of the complex solution structures frequently encountered in analytical solutions for three-phase flow may be the consequence of permeability models with little or no physical basis.

To the best of our knowledge, this is the first study to perform an analysis of the effect of physically-based relative permeabilities, using a description of the pore space and its connectivity that mimics real systems, on the saturation paths and secondary oil recovery by immiscible gas injection.
Advanced Formation Testing in OBM Using Focused Fluid Sampling for Producibility Evaluation in Mature Fields
Authors: Beaiji T. , Zeybek M. , Crowell A. , Akkurt R. , Al-Dossari S. , Amin A. , Crary S.
Published: December 2007

Wireline formation testing provides formation pressures, high quality samples and fluid identification/characterization. In addition, it can provide information for reserve assessment and producibility estimation.

In this paper, we present comprehensive formation evaluation case histories with formation testing utilizing a focused sampling probe in wells drilled with Oil Base Muds (OBM) in mature fields. Due to OBM and low mobility sections, a new focused sampling device was utilized for effective formation testing and sampling purity. One case history demonstrates confirming remaining oil saturation. Conventional open hole and Nuclear Magnetic Resonance (NMR) logs were run for formation evaluation, and fluid saturations. Gas and remaining oil saturation were obtained from 3D NMR analysis. Sampling lab results and real time analysis of gas compositions are also compared for verification and confidence.

Two field examples in low porosity/low mobility zones are presented showing the identification of mobile fluids. It is shown that the existence of mobile oil could have been missed without effective formation testing practices.

The third field example of formation testing with low porosity as well as low resistivity is provided for the identification of mobile oil. Flow was enabled from low mobility zones along with low rate pumpout that would not be possible with traditional probe and pumpout devices.

The final field example of water sweep evaluation in high permeabilitiy/mobility zones demonstrates using formation testing as a means of reservoir monitoring.
Forecasting Injector-Producer Relationships From Production and Injection Rates Using an Extended Kalman Filter
Authors: Liu Feilong , Mendel Jerry M.
Published: December 2007

This paper presents an adaptive method, using an Extended Kalman Filter (EKF), to forecast the injector-producer relationships (IPRs) between multiple injectors and a single producer based on measured production and injection rates.

For this method, we used a very simple parametric model, one with two parameters per injector, so that if a producer depends upon N injectors our model contains exactly 2N parameters. The EKF is used to adaptively estimate the 2N parameters, from which the IPR between each injector and a producer is then estimated.

This approach was tested on both synthetic and real data. The former used Monte-Carlo simulations, whereas the latter used data from one of Chevron's oil fields. Test results on synthetic data demonstrate the feasibility of the EKF method, and test results on the real data match other field indications about the IPRs between injectors and a producer. All results confirm that this EKF method may provide a good way to infer and track the IPRs, and may provide better insight about the IPRs.
The Effect of Volume Changes Due to Mixing on Diffusion Coefficient Determination in Heavy Oil and Hydrocarbon Solvent System
Authors: Luo H. , Salama D. , Kryuchkov S. , Kantzas A.
Published: December 2007

The diffusion coefficient is a key parameter to describe promising solvent - based technologies for heavy oil and bitumen recovery. In this work, an extended diffusion model considering the volume changes on mixing was used to calculate the mutual diffusion coefficients for the heavy oil -hydrocarbon solvent system. The approach requires not only concentration profiles, but also data on volume changes in the process of mixing. The concentration profiles were obtained from diffusion laboratory experiments in which X-ray Computer Assisted Tomography (CAT) was used to measure the density distributions at different times. In addition, the volume changes data was obtained by performing heavy oil and hydrocarbon solvent mixing experiments at different content of solvent in heavy oil.

By comparing the diffusion coefficient versus concentration curves based on the extended diffusion model and on the usual diffusion model (1), it was concluded that the volume changes due to mixing make significant differences to the diffusion coefficient determination in heavy oil – hydrocarbon solvent system, and the mutual diffusion coefficients are strong functions of concentration, which is consistent with previous literature.
Overcoming the Weak Link in Cemented Hydraulic Isolation
Authors: Moroni N. , Panciera N. , Zanchi A. , Johnson C. R. , LeRoy-Delage S. , Bulte-Loyer H. , Cantini S. , Belleggia E. , Illuminati R.
Published: December 2007

Preventing unwanted migration of hydrocarbons has been an enduring challenge to the oil and gas industry. Regulations are in place to minimize the risk of leaking wells. However, future regulations are expected to become increasingly restrictive requiring operators to minimize the risks of potentially unwanted hydrocarbon migration during the well planning stage.

Hydrocarbon flows may originate from pay zones, or from non-commercial hydrocarbon-bearing formations. Some of the most hazardous gas flows have originated from unrecognized gas behind conductor, surface or intermediate casing. Often determining the precise source of annular flow is difficult.

There are numerous short-term solutions aimed at preventing the flow of hydrocarbons including optimizing stand-off, fluid placement, slurry design and mechanical methods. These techniques relate to working with the cement slurry in its liquid state prior to curing, and are aimed at preventing undesirable movement of hydrocarbons within the cemented annulus before the cement has set. However their effectiveness is lost once the cement has set, making it vulnerable to hydrocarbon migration should cement sheath damage occur.

The paper describes a unique isolation solution based on a responsive cement system with intrinsic self-healing properties automatically activated upon hydrocarbon exposure. Activation occurs whenever the integrity of the cement sheath is compromised, e.g. cracks and microannulus, and then efficiently seals the leak path by a swelling mechanism. The solution rapidly forms a complete hydraulic barrier by healing damage, and continues to re-seal should further damage occur. The technical advantages of this solution are shown, illustrated through successful field tests.
Crosswell Electromagnetic Tomography in Haradh Field: Modeling to Measurements
Authors: Marsala Alberto F. , AlRuwaili Saleh , Ma S. Mark , Modiu Sanni L. , Ali Zaki , Donadille Jean-Marc , Wilt Michael
Published: December 2007

Crosswell electromagnetic (X-well EM) resistivity is emerging as an intriguing technology for reservoir surveillance. It provides a cross-sectional resistivity image between two wells and has the potential to provide fluid distribution at an inter-well scale. It can be used for identifying bypassed hydrocarbons, monitoring macroscopic sweep efficiency, planning infill drilling, and improving effectiveness of reservoir simulation. It can be deployed for one-time or time-lapse surveys.

A crosswell EM technology trial project is being conducted in an Upper Jurassic carbonate reservoir, at the Ghawar Field in Saudi Arabia, to monitor the movement of injected water flood front and map the fluid distribution. The project site is in Ghawar's southern region, Haradh Field, and consists of three wells in the oil-water contact zone where peripheral injection water may have produced an uneven flood-front distribution.

Significant drilling and well deepening were required prior to the deployment of tools in the three-well triangle. In fact, one new well was drilled and two other wells were deepened by more than 200 m, so that good volumetric coverage could be obtained at the oil- water contact zone. Extensive logs, core and formation tests were also acquired to provide deterministic saturation profiles at the near wellbore region. Formation evaluation in the project area indicates that one of the wells was fully swept while a second well, some 400 m away, was not.

In July 2007, crosswell EM surveys were acquired across the three Haradh wells. In spite of the large well separations, the acquired EM data had good quality, and good stations repeatability. Preliminary processing has revealed a structure consistent with the background structure but a clear image of the oil-water contact is yet to be made.
Laboratory Experimental Results of Huff ‘n’ Puff CO2 Flooding in a Fractured Core System
Authors: Asghari K. , Torabi F.
Published: December 2007

In this study, the performance and efficiency of CO2 huff-and-puff process for improving oil recovery and subsequent storage of CO2 in fractured porous media is examined and the results of laboratory tests are presented. The experimental set up consisted of a high-pressure stainless steel cell made specially to hold a cylindrical core with spacing around it to simulate fractures surrounding matrix. The matrix was saturated with normal decane, which was used as oil during these experiments. Over six sets of huff-and-puff experiments, using CO2 as solvent, were conducted for pressures of 250, 500, 750, 1000, 1250, and 1500 psi. Each set of the huff-and-puff experiments were conducted by injecting CO2 in the fracture surrounding the core (injection step). Then, the system was shut-in for a period of 24 hours to allow CO2 to diffuse from fracture into the oil in matrix (soaking period step). At the end of soaking period, the pressure was released and the oil production was measured (production step). The above cycle was repeated until no more oil was produced. The results obtained showed that CO2 huff-and-puff process improves the oil production from fractured media, significantly. These results also indicate that the oil recovery is higher for huff-and-puff experiments conducted at higher pressures.
Infinite-Acting Physically Representative Networks for Capillarity-Controlled Displacements
Authors: Behseresht Javad , Bryant Steven L. , Sepehrnoori Kamy
Published: December 2007

Drainage/imbibition simulations are traditionally performed on finite regular lattices. If physically representative networks are used instead, the spatial correlation of pore space features inherent in granular materials is automatically accounted for. However, even these networks are obtained from finite samples, and conditions must be specified on the boundaries. Making the conditions correspond to physically realistic situations is difficult, especially for simulations of phase trapping. This paper presents a method of constructing infinite-acting model rocks, in which a well-defined criterion for phase trapping is possible that is independent of boundary conditions. The foundation of the model is computer generated dense random periodic packings of spheres. We illustrate the method with simulations of drainage and irreducible wetting phase saturations. To eliminate possible confounding effects from grains being arranged differently, we compare simulations in infinite-acting networks with simulations in the finite network taken from the unit cell of the periodic packing.

Wetting phase connectivity is assessed globally and accounts for all phase morphologies, including pendular rings. This enables a physically rigorous method of identifying clusters of trapped pores: A "wrap-around" cluster of wetting phase is effectively infinite, and drainage of one or more pores in the cluster is deemed possible. All other clusters of wetting phase cannot undergo further drainage. Qualitatively different behavior is observed than when local connectivity criteria are used for trapping.

The nonwetting phase percolation threshold and the drainage endpoint are not sensitive to the choice of inlet pores in infinite-acting networks. For a finite network the percolation threshold was similarly insensitive, but the drainage endpoint was highly sensitive to the number and location of the exit pores. Comparison with experiments showed that a strict criterion of wetting phase connectivity (pores connected only by throats filled with wetting phase) cannot account for typical values of Sw,irr and that connectivity must persist via pendular rings.

Typical laboratory experiments and simulations in finite networks yield drainage curves that approach irreducible wetting phase saturation Sw,irr gradually, with large changes in capillary pressure inducing only small changes in saturation. Simulations in infinite-acting networks do not exhibit this behavior. We argue that these simulations are more representative of behavior in the field, and that typical laboratory measurements underestimate the value of Sw,irr.
Unique Micronized Weight Material Delivers Ultra-Thin NAF to Optimize ERD Drilling
Authors: Matlock Wayne , Conn Lee
Published: December 2007

A newly introduced dry micronized weight material (MWM) designed to improve hydraulic pressure management while mitigating sag tendencies for drilling challenging extended-reach wells has been used successfully in recent Gulf of Mexico drilling projects.

The application of the MWM while drilling narrow hydraulic windows, typically observed in deepwater wells, has led to new breakthroughs in the ability to model and manage the physio-chemical interactions of extremely small weighting agents with the chemicals and base fluids that constitute non-aqueous fluid (NAF) systems. From these advances, it is now possible to design and utilize weighted fluids that are ultra-thin, and possess significantly lower viscosity than fluids using traditional weighting materials.

Observations from both laboratory and field tests indicate a very stable NAF can be maintained with much lower equivalent circulation densities (ECD), reduced surge/swab pressures, and lower surface pressure requirements. Another observation using MWM is reduced friction. These factors have allowed users of the MWM to improve drilling performance by increasing flowrates for borehole cleaning while reducing excessive pressure spikes resulting from elevated viscosity and cuttings accumulation. Although the viscosity characteristic of MWM formulated fluids are very low, barite sag or settling potential is minimized or eliminated. The ultra-thin rheological values are designed to deliver improved drilling performance by establishing an optimized operating window determined from hydraulic modeling.

This paper will discuss the background development work on this new MWM, and provide details from the first field trial in which the new fluid system was used on a critical extended reach deepwater project. Additional field performance data from subsequent field trials will also be presented, where the improved hydraulic pressure management benefits from the new MWM is clearly demonstrated.