bluuebunny/crossref_metadata_2025 huggingface dataset:
Formation Evaluation in Thin Sand/Shale Laminations
Authors: Minh Chanh Cao , Joao Isabel , Clavaud Jean-Baptiste , Sundararaman Padmanabhan
Published: December 2007

Formation evaluation in thin sand-shale lamination seeks first to determine sand resistivity, volume fraction, and porosity. Afterwards, saturation and volume are simple Archie applications. Resistivity anisotropy techniques can provide estimates of sand resistivity and volume fraction, but good results depend on the choice of the anisotropic shale point. The same shale point should be used in the determination of sand porosity. Difficulties will arise when anisotropy is not caused by sand-shale laminations, when no sand-shale point exists, or when the nearby thick sand-shale is not representative of the sand-shale in the laminations. In producing fields that have undergone several waterfloods, water resistivity is often unknown in the swept thick sands and might not be representative of the water in the unswept thin sands.

As discussed previously, NMR offers useful insights into the petrophysics of thin sand-shale laminations. Typically, 1D high-resolution data is acquired to estimate sand volume fraction, porosity, and permeability, and 3D fluids data is used to evaluate the hydrocarbon type and content in the thin sands. However, shallow depth of investigation, slow logging speed, and sometimes unfavorable signal-to-noise ratios limit the applicability of the NMR technique.

In this paper we first demonstrate the variability of sand resistivity, volume fraction, and porosity output depending on the input parameters. Next, we show the complementary aspects of the resistivity anisotropy and NMR techniques. Since several are the same or determined independently, using both datasets ensures more plausible results in thin beds than either stand-alone technique could provide. Field examples of a straightforward case with a well-defined anisotropic shale point, as well as a difficult case with multiple shale points, are used to demonstrate the new workflow. In general we see improvements in the estimation of the hydrocarbon in place; however, not all thin beds offer large hydrocarbon volumes.
A New Approach for Interpreting Pressure Data To Estimate Key Reservoir Parameters From Closed-Chamber Tests
Authors: Rahman N. M. A. , Santo M. S. , Mattar L.
Published: December 2007

A new technique for analyzing and modeling the pressure data from both flow and buildup periods in closed chamber tests (CCT) has been developed. It can be used for estimating the key reservoir parameters such as reservoir pressure, permeability and skin.

There are two aspects of the proposed approach - straightline analysis and modeling. A novel approach is taken to develop the analytical solutions and procedures for both liquid and gas wells. Approximate solutions for the early-time and late-time pressure behavior are derived from the rigorous solution and are used for developing the basis for the straightline analysis. A derivative function is utilized to ascertain if the data contains any portion of reservoir-dominated flow. Two synthetic data examples are presented to illustrate the process.

Important contributions made in this study are as follows:

The analysis procedure is simple enough to implement in a spreadsheet, but is more accurate than the currently available methods. Calculating influx rates during the drawdown period is not an essential part of the analysis or modeling. Thus, any noise in the data would not aggravate the accuracy of calculations. The complete analytical solution for modeling the entire CCT data will allow one to investigate possible test durations for CCTs, and also to refine the parameters determined from approximate analyses.

The presented technique is also applicable for analyzing drillstem test (DST) data, as long as the flowing fluid does not reach the surface.
Experimental Investigation of Emulsion Stability in GOSPs, Part II: Emulsion Behavior
Authors: Al-Ghamdi A. M. , Noïk C. , Dalmazzone C. , Kokal S.
Published: December 2007

This paper presents an experimental study performed jointly by IFP and Saudi Aramco to characterize the stability of emulsion samples collected from different Saudi Aramco Gas Oil Separation Plants (GOSPs). The first part of the study1 (SPE 106128) focused on the analyses of separated phases. Many techniques (differential scanning calorimeter, Karl Fisher coulometer, rheology, optical microscopy, cryo-scanning electron microscope) were applied to analyze and characterize the separated phases: crude oil, emulsion and free water. In the second part of this study, the stability of residual emulsions was investigated against several chemical demulsifiers by using classical bottle tests and an automated, vertical-scan, macroscopic analyzer (Turbiscan). This instrument is used to obtain kinetics of separation of concentrated and opaque dispersed systems such as emulsions, suspensions and foams. Interfacial tension measurements were also made to obtain information about the interfacial behavior of samples including viscoelasticity properties of the film. The results of transient emulsion separation experiments provide some useful insights into their behavior, stability and tightness. The study highlights the main physicochemical parameters responsible for the varying tightness of these emulsions, and provides recommendations to optimize their treatment costs and resolve emulsion issues in the GOSPs.
Seismic-While-Drilling Operation and Applications
Authors: Dethloff Morten H. , Petersen Steen Agerlin
Published: December 2007

Even though the seismic while drilling (SWD) tool is coupled to the Bottom Hole Assembly like a standard tool its operation and setup is far from standard. It requires proper planning ahead of the acquisition and a proper understanding of the full potential of the data to make this service a powerful drilling decision tool.

The SWD full value can only be attained through a holistic approach. This paper will discuss the necessity of effective communication and planning for the successful outcome of a complex SWD operation. A proper time line, project management and focus on all parties involved are essential for the SWD operation to be successful without disturbance of the drilling operation.

SWD has the potential of producing a real time update to the geological model. It offers improved resolution and more accurate depth conversion. Due to the flexibility of source/receiver positioning several other geophysical applications will be possible. Salt flank and fault plane imaging are two examples of these applications. The challenges encountered for alternative source/receiver positions will be analyzed.

The SWD service has the potential of becoming a key drilling decision tool. The necessity of applications, resources, cooperation and decisions will be analysed. The need for developing a team effort and common set of tools is described. Uncertainties in data quality coupled with surface seismic limitations lead to a risk management process. This requires a proper understanding of the workflow of seismic processing and reservoir properties to minimize time for data preparations prior to evaluation and decisions.
Developing a Holistic Global Approach to Asset Management
Authors: Cabrera Benito , Musri Daniel , Selva Carlos , Lardone Carlos
Published: December 2007

The oil and gas industry has made great strides in the individual applications of the intelligent oil field technologies. However, the "big prize"—the integration of the individual pieces into a comprehensive solution that transforms work processes to achieve step-change efficiencies in development and operations—has been more elusive.

This paper chronicles the work and resulting methodologies of the international unit of an oil company as it implements an open platform asset management solution in a newly producing field, and adapts and transforms related processes to develop a template for re-use in assets anywhere in the world to anticipate and pre-empt problems—essentially realizing the promise of the intelligent oil field.

This holistic approach begins at the static model and includes reservoir simulation, surface facilities, processing plants, through economics, thereby making available the comprehensive technical picture to all geoscience and engineering professionals, and providing the basis for sounder economic decisions.

The development of this methodology is possible because of the ability to exploit these factors:

A relatively new field coming online, with limited production problems, provides a solid starting ground on which to develop the methodology. Implementation of the most current asset management solution, based on an open platform that will allow the integration of other technology for the full spectrum of upstream applications, from static model through economics, provides the right technology. A commitment from the operator to not simply implement the solution, but to dedicate the resources to assess and analyze the workflow and processes, and combine the expertise of the operator, service company and consultants to develop methodologies that can be applied globally, to any operations.
Experiences with Streamline-Based Three-phase History Matching
Authors: Oyerinde Adedayo , Datta-Gupta Akhil , Milliken William
Published: December 2007

Streamline-based assisted and automatic history matching techniques have shown great potential in reconciling high resolution geologic models to production data. However, a major drawback of these approaches has been incompressibility or slight compressibility assumptions that have limited applications to two-phase water-oil displacements only. Recent generalization of streamline models to compressible flow has greatly expanded the scope and applicability of streamline-based history matching, in particular for three phase flow. In our previous work, we calibrated geologic models to production data by matching the water-cut and gas/oil ratio using the generalized travel time inversion (GTTI) technique. For field applications, however, the highly non-monotonic profile of the gas/oil ratio data often presents a challenge to this technique. In this work we present a transformation of the field production data that makes it more amenable to GTTI. Further, we generalize the approach to incorporate bottom-hole flowing pressure during three-phase history matching. We examine the practical feasibility of the method using a field-scale synthetic example (SPE-9 comparative study) and a field application. The field case is a highly faulted, west-African reservoir with an underlying aquifer. The reservoir is produced under depletion with three producers, and over thirty years of production history. The simulation model has several PVT and SCAL regions and over a hundred thousand cells. The GTTI is shown to be robust because of its quasi-linear properties as demonstrated by the water-cut and GOR match for a period of 30 years of production history.
Determination of Connected Volume and Connectivity From Extended Tests in Compartmentalized and Layered Reservoirs
Authors: Larsen Leif , Straub Richard Benjamin
Published: December 2007

Tests from compartmentalized and layered reservoirs can be difficult to interpret for connected volume and connectivity. The problem comes from the timing of the response from "primary" and "secondary" drainage volumes, either as well-compartment and distant compartments or as dominating and dominated layers, with reduced communication between volumes posing more challenges. Although simple material balance considerations can be used to estimate the total volume, the difficulty lies in determining individual volumes and connectivity. The term "connectivity" is used here in a broad sense to cover effects of differential depletion, a critical element of recovery from compartmentalized reservoirs.

Results from the paper are applied to both pressure transient tests and to production data (rate data) analyses based on decline curves and type curve methods. For pressure transient tests the distinction between extended buildup behavior and single-rate extended drawdown behavior, e.g., based on deconvolution data, is of particular importance, with different boundary characteristics picked up from the two data types. For production data analyses the main challenges are associated with effects of differential depletion and the concept of boundary dominated flow both for closed systems and for systems with pressure support or influx. Similar challenges apply to compartmentalized systems produced under simple depletion and pseudosteady state conditions.

In order to separate facts from fiction, all examples are based on analytical and numerical models. This is important since critical parameters such as pressure communication and flow between compartments and between layers must be known in order to determine how these effects can be properly investigated and understood based on pressure transient and well performance data. The basic analytical model used in this paper is fully transient with flow based on local gradients rather than on differences in average pressures between compartments which tend to yield data with delayed and exaggerated response.
A Compendium of Directional Calculations Based on the Minimum Curvature Method: Part 2
Authors: Sawaryn S. J. , Tulceanu M. A.
Published: December 2007

The point to target calculations contained in part one of the compendium1 were restricted to those cases in which the 3D target coordinates were stated explicitly. However, another class of problems exists where the target's structural position is determined indirectly from other constraints defining the arc's orientation. This new paper builds on the earlier work and contains complete details of twelve explicit algorithms, including the calculation of a target based on the toolface at the start or end of an arc and for the landing of a well path parallel to a formation bedding plane.

These cases find practical application in computing trajectories of motor runs and in whip-stocking operations. The curvature of the trajectory landing on a bedding plane varies with direction and has a distinct minimum and maximum. These values may be used to either minimise the distance to the target or limit the dog leg severity to avoid drill-pipe fatigue, a concern in short radius drilling applications.

The algorithms add to the compendium and are useful extensions to the engineer's computational toolkit. The paper shows that the trajectories, computed using the minimum curvature calculation are contained on the geometric surfaces defined by a torus or cyclide. These geometries explain why the explicit solutions exist, opening up possibilities for obtaining solutions to the more complex cases.
Development of Deep Thin Reservoirs Through Meandering Morphologies Imaged in Seismic Data—A Case Study in San Jorge Basin, Argentina
Authors: Foster Martín , Iovine Gastón
Published: December 2007

This study was focused in the North of Los Perales Field, in San Jorge Basin, Argentina where very good results were obtained identifying extremely heterogeneous fluvial channel reservoirs by using strata slice seismic amplitude data combined with Spectral Decomposition. This last method is a relatively new technology and proved to be useful for mapping thin layers below the seismic resolution. The fluvial channels are well mapped in Castillo Formation, a multilayer reservoir characterised by sandstone bodies deposited by fluvial river systems with high pyroclastic content.

Although more than 3000 wells have been drilled in the field, few ones have reached the deep reservoirs in Castillo Formation.

We showed how the wells LP-2339 and LP-2355 have been drilled in order to evaluate the morphologies visualised with seismic data and how their productions are highly up the average well production in the field.

Seismic cubes at different frequencies were generated, and by blending some of them, it was possible to visualise different channels facies. The thin layers thickness of the reservoir in time produce tuning effect enhancing the frequency data allowing to understand the meandering morphologies representing fluvial channels, its possible depositional environment, and the paleocurrent in the main productive Formations. Because of the sand layer thickness and petrophysical properties of the reservoir, it was not possible to determine the reservoir fluid content by using seismic data alone, but now we know that all of the meandering morphologies showed in strata slices correlates perfectly well with high acoustic impedance sandstones.

These results, give us an extremely useful tool to improve well location in San Jorge Basin, especially in the western zone where the contrasts of impedance between sandstone and tuff are important.

Finally based on this study, new reserves will be incorporated in the area and a new development front is now open in this mature field.
Surface Tiltmeter Mapping Shows Hydraulic Fracture Reorientation in the Codell Formation, Wattenberg Field, Colorado
Authors: Wolhart Steve , Zoll Mike , McIntosh Greg , Weijers Leen
Published: December 2007

This paper reports on a study conducted to measure the orientation of fractures created during initial fracture and refracture treatments in the Codell formation of the Wattenberg Field, Colorado. The Codell is a thin, low permeability sandstone that is laterally continuous across the field area. Due to the low permeability, stimulation is required for economic development of the Codell. Refracturing of Codell wells in Wattenberg Field has been successfully performed for the last decade and several reasons have been suggested for the success of Codell refracs including reorientation of fractures.

Surface tiltmeter mapping was performed during this study on several initial fracture and refracture treatments in the field to determine fracture orientation. The average azimuth of initial fracture treatments was N66°E. Significant reorientation occurred on some refrac wells and the average azimuth of refracture treatments was N29°E although highly variable.

It has been observed that fracture orientation can vary due to changes in pore pressure as the result of asymmetrical depletion and/or injection or due to structural features. In this case we believe that asymmetrical depletion is affecting the in-situ stress orientation and thus the fracture orientation. There were also indications of fracture complexity with some treatments showing a change in fracture orientation during the treatment and several showing higher than normal horizontal components.

The results from this study help explain the success of refracture treatments in the Codell. Refracture reorientation allows existing wells to contact new reservoir increasing gas recovery per well. There may be the potential to fracture wells for a third time (re-refracs) for additional fracture reorientation and improved gas recovery. Mapping and production results are discussed in this paper.
Performance Step Change: 3 Years of Advances in CNS Britannia Field, UK
Authors: Matheson Elizabeth , Phillips Alan , Bradley Scott , Wallace Graeme
Published: December 2007

This paper describes advanced PDC technologies applied to the challenging 12-1/4 inch section in the Britannia field in UK Central North Sea (CNS) that significantly reduced the number of bit trips and associated drilling costs. The 12-1/4" section is generally drilled in three main intervals with RSS/PDM.

New PDC bit technology was developed to efficiently drill two of these sections with controllable torque response and consistent directional behavior while achieving maximum ROP and durability. Several new bit designs were implemented and tested at the manufacturer's surface simulator with good results.

The upper interval from the 13-3/8" shoe originally used 8- bladed 13mm cutter PDC down to the Maureen limestone (USC c.15,000psi). A 19mm 7-bladed PDC featuring reduced exposure and advanced cutter technology was introduced. This design achieved a drilling record from the 13-3/8" shoe to the top Tor in one run where previously two bits had been required. In addition there was improved steerability on a motor through the Lista Formation; previously this had been considered directionally challenging. The same section on the next well with this bit design achieved a field footage record of 9,534ft.

The lower Cretaceous chalk section from the top Tor was originally drilled with 6-bladed PDC with 16mm/13mm cutters. Historically PDC bits slowed to unacceptable ROP with only minimal wear due to the rounded diamond lip proving unable to penetrate the Chalks. An application specific 7 bladed 16mm cutter design was introduced featuring latest technology cutters, and a customized back up cutter layout. This design drilled 4,500ft from the top Tor Formation with no visible wear. This section had previously required 2-3 PDC bits. During this same time, the service company was also matching the closed-loop RSS system with the ever changing PDC bit technology. The development of the RSS in combination with the advancing PDC technology played a large role in the performance improvement. The authors will describe field results and developments leading to this performance step-change.
A Triple-Continuum Pressure-Transient Model for a Naturally Fractured Vuggy Reservoir
Authors: Wu Yu-Shu , Ehlig-Economides Christine , Qin Guan , Kang Zhijiang , Zhang Wangming , Ajayi Babatunde , Tao Qingfeng
Published: December 2007

We present an analytical approach for pressure transient test analysis in naturally fractured vuggy reservoirs. This analysis approach relies on a triple-continuum concept, using observed geological data from carbonate oil formations in western China, to describe transient flow behavior in fracture-vug-matrix reservoirs. In the conceptual mathematical model, fractured vuggy rock is considered as a triple-continuum medium, consisting of fractures, rock matrix, and vugs (or cavities). Similar to the classical double-porosity model, the fracture continuum is assumed to be responsible for the occurrence of global flow, while vuggy and matrix continua (providing primary storage space) interact locally with each other as well as with globally connected fractures. Furthermore, the triple continua of fractures, matrix, and vugs are assumed to have uniform and homogeneous properties throughout, and intercontinuum flows between them are at pseudosteady state. With these assumptions, we derive analytical solutions in Laplace space for transient flow toward a well in an infinite and finite reservoir with wellbore storage and skin effects. The analytical solutions reveal typical pressure responses in a fracture-vug-matrix reservoir and can be used for estimating vug properties, in addition to fracture and matrix parameters, through properly designed and conducted well tests. As application examples, actual well test data from a fractured-vuggy reservoir in Western China are analyzed using the triple continuum model.
A Two-and-Half-Dimensional Model-Based Inversion Algorithm for the Controlled- Source Electromagnetic Data
Authors: Abubakar Aria , Habashy Tarek M. , Zhang Yan
Published: December 2007

The model-based inversion method for the reconstruction of geometry and conductivity of unknown regions or bodies using marine controlled-source electromagnetic (CSEM) data is presented. The method has the advantage of using a priori information such as the background conductivity distribution, structural information extracted from seismic and/or gravity measurements, and/or inversion results a priorily derived from a pixel-based inversion method. By incorporating this a priori information, the number of unknown parameters to be retrieved becomes significantly reduced. In this paper, we develop the model-based inversion method by adopting the regularized Gauss-Newton minimization scheme. The robustness of the inversion is enhanced by adopting nonlinear constraints and applying a quadratic line search algorithm to the optimization process. We also introduce the adjoint formulation to calculate the Jacobian matrix with respect to the geometrical parameters. We compare the inversion results obtained by the model-based inversion method with those obtained from the pixel-based inversion method.
Monitoring Production from Gravel-Packed Sand-Screen Completions on BP's Azeri Field Wells Using Permanently Installed Distributed Temperature Sensors
Authors: Pinzon I. D. , Davies J. E. , Mammadkhan F. , Brown G. A.
Published: December 2007

BP is developing its Azeri field using deviated gravel-packed sand-screen completions producing from the multilayered Pereriv B, C, and D reservoirs. Restricted wellhead access, high rates, and differential depletion of the different reservoir intervals limit conventional production logging possibilities, so BP has chosen to install permanent fiber-optic distributed temperature monitoring systems with its sand screens and to use these systems to monitor production rates and changes over time.

The optic fiber has been installed on the periphery of the sand-screen shroud, effectively installing it in the gravel-packed annulus. When the gravel pack is completed, the fiber responds to the reservoir temperature plus the effect of Joule-Thomson warming of the flowing oil caused by the pressure drop (drawdown) in the near-wellbore region. Thermal mixing of the oil with flow from below only occurs once the flow has passed through the sand-screen wire-wrap. Thus a direct measure of each individual reservoir drawdown is obtained from the difference between the fiber-measured temperature and the geothermal temperature in the flowing reservoir intervals. Given the reservoir drawdown, the flow rate can then be calculated.

Thus installing the fiber outside the sand-screens gives a unique, direct measurement of individual reservoir layer drawdowns, enabling the effects of differential depletion to be monitored over time.

This paper outlines the completion technology used to install the fibers along the sand screens and shows the data and results obtained where reservoirs with different pressures are commingled through gravel-packed sand-screens. Thermal models of the near-well environment are described and used to analyze the data and to obtain the flow profile and reservoir layer pressures.

The use of permanently installed fiber-optic distributed temperature monitoring systems on its Azeri reservoir has allowed BP to acquire early time-surveillance data, adding significant value by reducing the voidage risk to the secondary reserves.
Calibrating the Mechanical Properties and In-Situ Stresses Using Acoustic Radial Profiles
Authors: Sayers Colin M. , Kisra Saad , Tagbor Kwasi , Taleghani Arash Dahi , Adachi José
Published: December 2007

Estimating the in-situ stresses and geomechanical properties in the exploration phase is key to the success of drilling, completion, and production operations. A methodology for building a Mechanical Earth Model (MEM) along a well trajectory based on logs and drilling data is presented. The constructed MEM uses the acoustic radial profiles obtained from a multi-pole sonic tool. The variation in the velocity of polarized shear waves as functions of the distance from the borehole are used to provide estimates of the magnitude and orientation of the in-situ stress state as well as to calibrate the stresses obtained using other methods. Furthermore, a plane strain computational model accounting for rock deformation and plastic strain in the near-wellbore region resulting from the stress changes induced by drilling is used. This model allows us to provide calibrated estimates of the unconfined compressive strength of the sand bodies crossed by the well.
Is Accurate Gas/Steam Determination Behind Pipe Feasible with Pulsed Neutron Measurements?
Authors: Badruzzaman A. , Logan J. P. , Bean C. , Adeyemo A. O. , Zalan T. A. , Barnes D. , Platt C.
Published: December 2007

Pulsed neutron measurements are commonly used to locate gas behind casing and quantify steam saturation, but do not always yield desired results. Several parameters are utilized to identify gas and one parameter, the thermal neutron capture cross section, Sigma, is used to compute steam saturation. In the paper we report a mixed experience in identifying gas with these techniques, across fields, tools and vendors. Some parameters have worked well in some cases but have performed poorly in others. The uncertainty in steam saturation, computed using Sigma, is greater than those previously reported elsewhere. Modeling offers insight into the mixed results. It appears that in some cases the PNC-derived Sigma may yield erroneous steam saturation for a variety of reasons, including uncertainties in the input parameters and possibly an inherent nonlinear transport effect that increases as steam saturation increases. An alternative approach based on PNC pseudo-porosity is explored. Calibration of cased-hole tools in gas reservoirs, generic and local, open-hole baseline data and core analysis of complex rocks are essential. Currently, these are either nonexistent or infrequent.
Fracture Characterization and Modeling Various Oil-Recovery Mechanisms for a Highly Fractured Giant Light-Oil Carbonate Reservoir
Authors: Ayyalasomayajula Padmakar , Hui Mun-Hong , Narr Wayne , Fitzmorris Robert , Kamath Jairam
Published: December 2007

Proper fracture characterization and a good understanding of the fracture-matrix system are critical to properly predict oil recovery from naturally fractured reservoirs. In this work, we use an integrated analysis of image logs, production logs, and production history to help constrain matrix and fracture properties. This is done by extracting a sector from the history-matched full field model of a naturally fractured giant light oil carbonate reservoir and explicitly studying matrix fracture flows.

Even with constraints provided by the above analysis, there is still significant uncertainty regarding matrix permeability in our reservoir. We built simple mechanistic models to study the impact of this uncertainty on various oil recovery mechanisms such as miscible gas injection and primary depletion. We also quantified the impact of capillarity, diffusion and gravity on recovery mechanisms.
Optimized Formation Evaluation: A New Technique to Enhance Openhole Log Assessment of Pay and Producibility
Authors: Eyvazzadeh Ramsin Y. , Bradford Charles , Kersey David G. , Al-Waheed Hilal H.
Published: December 2007

Improving the accuracy of petrophysical analyses is critical in optimizing formation evaluation. Petrophysical accuracy is affected by errors inherent in log and core measurements and reservoir heterogeneity. These errors can lead to imprecise differentiation of pay and non-pay resulting in either overlooked pay or additional testing costs. Error reduction will improve the differentiation of pay/non-pay but, due to remaining errors, the distinction will still be imprecise. Thus to optimize formation evaluation, it is imperative to quantify remaining errors.

This paper presents a newly developed technology that quantifies petrophysical uncertainty to maximize the utility of petrophysics in formation evaluation by incorporating Monte Carlo numerical analysis to account for uncertainties in log, reservoir and petrophysical parameters. In comparison to traditional petrophysics, this technique does not assume unique values for the input parameters used in calculation of hydrocarbon pore volumes and deliverability. This technique incorporates random errors in logging tool responses and core measurements as well as reservoir heterogeneity in a Monte Carlo simulation. Output from the Monte Carlo simulation is then used in appropriate petrophysical models (e.g. Archie, Dual Water, etc.) to calculate statistical distributions for saturation and permeability to define productive and nonproductive zones.

The novel aspect of this methodology is that it also identifies zones where the random measurement and model errors are too large to determine accurate saturation and permeability. In these zones of high uncertainty, saturation and permeability are "undetermined". Based on the amount of uncertainty, this technique can determine whether additional logging, coring or well test data are needed to reclassify "undetermined" zones as either productive or non-productive. This paper will outline the procedures used in developing the technique and will show its utility in several examples from Middle Eastern reservoirs.
Pushing the Boundaries of Artificial Lift Applications: SAGD ESP Installations in Canada
Authors: Gaviria F. , Santos R. , Rivas O. , Luy Y.
Published: December 2007

The need for high-temperature electric submersible pump (ESP) systems is growing as the oil industry matures. Canada's nonconventional oil reserves are estimated at just over 1 trillion barrels and Suncor's heavy oil reserves in northern Alberta, Canada, are estimated to have a potential production of 14 billion barrels of crude oil, but traditional mining methods of recovery do not make them all economically reachable. It is estimated that less than one-fifth of the oil sands resource is mineable. To deal with this, Suncor has turned to in-situ steam-assisted gravity drainage (SAGD) operations as a key part of its plans to increase bitumen supply to its upgraders.

The SAGD approach uses a pair of horizontal wells drilled parallel to each other and separated vertically by a distance of approximately 5 m. Steam injected through the uppermost well penetrates the surrounding formation, heats the heavy-oil sands, and creates a high-temperature region above the injector known as the steam chamber. Heat transferred to the oil sands reduces oil and bitumen viscosity. Gravity forces the oil, bitumen, and condensed steam downward, where these fluids, consisting of about 25–80% water, are produced into the lower well.

Suncor uses SAGD technology to recover 8 to 9 degree API bitumen and heavy oil from unconsolidated sands in the Firebag field. Wells in these fields experience bottomhole pressures of 2000 to 3000 kPa and bottomhole producing temperatures of 180°C to 209°C. Whereas standard ESP strings are rated to 149 °C, bottomhole operating conditions (BOC), key components of the SAGD system featured in this paper, especially its motor, power cables, pump, and advanced protector, are built to withstand bottomhole temperatures up to 218 °C.

Suncor has installed 21 of these ESP systems, which have enabled a reduction in downhole pressures to improve the steam/oil ratio (SOR). This is a direct reduction in operating and lifting costs, which provides several million dollars in savings by reducing the amount of water that needs to be treated and the amount of fuel burned to generate the steam. Suncor's line of ESP systems has achieved a runlife of more than 500 days.
Multiphase Flow Modeling Based on Experimental Testing: A Comprehensive Overview of Research Facilities Worldwide and the Need for Future Developments
Authors: Falcone G. , Teodoriu C. , Reinicke K. M. , Bello O. O.
Published: December 2007

Multiphase flow models for the oil and gas industry are required to investigate and understand the co-current or counter-current flow of different fluid phases under a wide range of pressure and temperature conditions and in several different flow configurations.

To compliment this theoretical effort, experimental measurements are required to verify multiphase flow models under controlled conditions and assess their range of applicability. This is why there exists a large number of multiphase flow loops around the world.

However, there are numerous varieties of multiphase flow occurrences due to differences in pressure and temperature, fluid types, flow regimes, pipe geometry, inclination and diameter, and whether the flow is steady-state or transient.

Consider the example of hydrocarbon producing fields in the North Sea. Typical parameters for an oil well in the northern basins are as follows: production rate of 800–1600 cubic meters per day, tubing diameter of 0.102–0.130 meters, reservoir depth of 3000–3500 meters, oil density of 825–930 kilograms per cubic meters, gas-oil-ratio of 100 standard cubic meters per standard cubic meters and water cut up to 90%. For a gas well in the southern gas basin, the typical parameters become: initial production rate of 0.7 to over 2.8 million standard cubic meters per day, tubing diameter of 0.114–0.140 meters, reservoir depth of 2500–3500 meters and initial liquid-gas-ratio of less than 1 to over 30 standard cubic meters per million standard cubic meters. The operational pressure at the wellhead may reach up to 10 MPa and reservoir pressures can be as high as 30 MPa. Furthermore, not only do well performance values vary considerably across the world and, they also vary with time for the same field.

Building a flow loop that reproduces real hydrocarbon wells, including the reservoir inertia and the complex heat transfer process taking place between the wellbore and the reservoir, is not feasible. Thus, downscaling of typical field parameters is necessary for the study of multiphase flows at laboratory conditions.

This paper presents a critical review of multiphase flow loops around the world, highlighting the pros and cons of each facility with regard to reproducing and monitoring different multiphase flow situations.

The authors suggest a way forward for new developments in this area.
Geomechanics Field and Laboratory Characterization of Woodford Shale: The Next Gas Play
Authors: Abousleiman Younane , Tran Minh , Hoang Son , Bobko Christopher , Ortega Alberto , Ulm Franz-Josef
Published: December 2007

Woodford shale is emerging as one of the major gas formations in the US Midwest. Despite its tremendous potential, existing data on the Woodford shale geomechanics characterization are limited at best. In this work, a well in the Woodford shale formation, 200 feet deep, was cored and logged in Oklahoma, USA. The resulting retrieved preserved cores were lab tested using standard acoustic techniques and triaxial testing for shale mechanical and poromechanical characterization in terms of compressibility, strength, pore pressure coefficient, Young's modulus, Poisson's ratio, etc. In addition, shale mechanical parameters alteration when in contact with drilling muds and fracturing fluids were measured using Brazilian tests and the innovative Inclined Direct Shear Testing Device (IDSTD™). Finally, mechanical Woodford shale parameters were also measured and correlated with field log results, using samples a tiny as drill cuttings (a few millimeters in size) with the newly emerging nano-indentation rock characterization techniques developed in the GeoGenome™ Industry Consortium. This newly developed methodology for rock testing and shale chracterization, part of the nanotechnology wave, showed excellent results when compared with shale acoustic laboratory measurements and log data and results.

Despite a relatively high quartz content as shown by XRD and Elemental Capture Spectroscopy (ECS) log results, the Woodford shale does exhibit clear transversely isotropic mechanical characteristics, from Young's moduli to Poisson's ratios and other mechanical parameters. Moreover, IDSTD™ and Brazilian tensile tests on the preserved Woodford samples exposed to different drilling and hydraulic fracturing fluids showed that fluid effects play an important role on both compressive strength and tensile strength of the shale despite the fact that the Woodford clay content mainly composes of illite and chlorite.

The mechanical and poromechanical properties of Woodford shale were measured at four different scales, from field well logs to standard rock testing to the penny-size samples of IDSTD™ and down to drill cuttings scales using the nano-indentation. Furthermore, the innovative nano-indentation techniques for rock testing have allowed the construction of a GeoGenome™ simulation model which can estimate and determine macroscopic rock properties based on porosity, packing density, and mineralogy. The simulated moduli and parameters using this model showed excellent agreement when compared to both lab and field log results.
Experimental and Numerical Investigations of Borehole Ballooning in Rough Fractures
Authors: Ozdemirtas M. , Babadagli T. , Kuru E.
Published: December 2007

Borehole ballooning/breathing is a combined mud loss/gain event observed during drilling operations in naturally fractured formations. Factors controlling this phenomenon must be well understood to correctly interpret its symptoms observed during drilling to avoid mixing ballooning with other formation flow incidents which might lead to unwarranted well control procedures.

A mathematical model defining the ballooning process was developed and solved numerically using finite difference approximation. It was shown that fracture roughness and fracture deformation play a significant role on the flow of drilling fluid in and out of a single fracture. In this study, the focus was mainly on the effect of fracture roughness (characterized by the fractal dimension of the fracture surface) and fracture aperture.

The main goal of this work was to compare the numerical model results with the laboratory scale experimental observations. Therefore, experiments were performed to study the mud loss and gain events in artificially fractured rock samples. One-inch diameter and 3-inches long cylindirical samples of Berea sandstone, Indiana limestone and granite were used for the experiments. Two different fracture types were used to analyze the effect of fracture surface roughness on the flow of drilling fluid in and out of the fracture. In order to create smooth fracture surfaces, cores were cut precisely into two equal pieces using a blade. Alternatively, axial load was applied on the cylindrical rock samples until a longitudinal fracture with rough surface was generated.

The results of experimental observations and numerical model study on the importance of fracture roughness were provided. Situations where the degree of roughness becomes critical were identified.
A Dynamic Model for High-Rate Acid Stimulation of Very Long Horizontal Wells
Authors: Mogensen Kristian , Hansen Jens Henrik
Published: December 2007

In 1999, Mærsk Olie og Gas AS introduced the Controlled Acid Jet (CAJ) completion and stimulation technique and over the last 7 years more than 300 km of reservoir sections have been implemented mainly in the Danish chalk fields (see SPE paper 78318 for a description of the concept). This method allows cost effective single operation acid stimulation of ultra long horizontal wells (15,000+ ft) in carbonate reservoirs. Successful implementation of the CAJ technique requires numerical modelling of the dynamics of the entire stimulation process to ensure equal distribution of the acid, effective control of the wormhole growth rate in all sections of the well, displacement of mud along the entire reservoir section, handling of significant (1,000+ psi) formation pressure gradients along the reservoir section etc. Especially the analysis of the mud displacement process along the horizontal sections has proven to be critical for optimising the completion design.

The key to the successful field developments has been the gradual improvement of the CAJ technique which has been achieved by modelling the effect of a range of parameters prior to the full field trial to optimise the design of the completions.

This paper describes the building blocks of the newly developed modelling algorithm* that captures the physics of the stimulation process and the numerical solution methods required to apply the CAJ technique in ultra long horizontal wells.

The model has been matched to actual stimulation data and modelling is now widely used resulting in more effective stimulation and an extensive application of the CAJ technique for the development of marginal fields.
Characterization of a Reef Reservoir Permeability Using Well and Seismic Data
Authors: Hu Guangyi , Huang Xuri , Mei Minxiang , Gu Li , Xiao Chaozheng
Published: December 2007

This study is based on a field development planning study of a reef reservoir with only one well and 3D seismic data. The reef has porosity of inter-grain, organically-derived pores and depositional or structural fractures. A high degree of heterogeneity of the reef reservoir makes the characterization more difficult. This work implemented an approach starting with core description, and deposition-driven interpretation, inversion and forward modeling of seismic data. Subsequently, pore structures, fractures and facies are identified using core description and logs. Fracture density is obtained from the core description for each facies. Porosity and permeability are statistically related using the core data according to the facies in the core. The matrix permeability field is generated in three dimensions based on porosity from the seismic. The fracture permeability is found to correlate with the matrix porosity from an adjacent reef field. However, due to the complexity of the fracturing in the reef, the core description needs to be corrected using the well test data and an analytical model of cracks, such that the core-described fracture can be equivalent to well test-detectable fractures. The fracture permeability is added to the matrix permeability according to the facies. Based on the different possible depositional models, the uncertainty is analyzed through the corresponding seismic inversions, and derived facies.
Successful Application of Chemical Injection Rate Control Valves
Authors: Duhon H. J. , Annadorai K. M.
Published: December 2007

This paper presents an overview of a systems approach to the design and troubleshooting of IRCVs (Injection Rate Control Valves) used in deepwater chemical injection systems. The inherent problems associated with these simple flow regulators stem largely from the failure of design engineers to take a systems view in design. Along with the application of lessons learned from previous IRCV system failures, this systems approach provides a design method which will allow users to avoid many of the pitfalls inherent in design, installation, testing, commissioning and operation of IRCV systems.
Multicomponent Sorption Modeling in ECBM Displacement Calculations
Authors: Jessen Kristian , Lin Wenjuan , Kovscek Anthony R.
Published: December 2007

Enhanced coalbed methane (ECBM) recovery by injection of CO2 or by injection of mixtures of CO2 and N2 is an attractive method to recover additional natural gas resources while at the same time sequestering CO2 in the subsurface. The dynamics of ECBM recovery processes are determined in large part by the sorption behavior of mixtures of CH4, CO2 and N2 on the coal surface. Conventional simulation tools use the extended Langmuir model for predicting the sorption behavior of the gas mixtures that form during a displacement process. In previous work, we demonstrated the applicability of this approach for binary CH4/CO2 and CH4/N2 displacements by comparison to lab-scale experiments. The extended Langmuir model was, however, unable to describe the behavior of ternary CH4/CO2/N2 displacements. Adsorption hysteresis is a complicating factor also. This paper investigates the accuracy of ternary gas displacement calculations. We find that a sorption model more sophisticated than the extended Langmuir model is needed to represent the dynamics of multicomponent systems. We use the Ideal Adsorbate Solution model (IAS) and compare the predicted behavior to standard calculations and experimental results.

Initially, we describe the implementation of the IAS model into our dual-porosity simulator. The IAS model requires an iterative scheme as opposed to the explicit calculation from the extended Langmuir model. Accordingly, the IAS model is more computationally expensive than traditional approaches. The predicted displacement behavior substantially agrees with the experimental observations in comparison to the inaccurate predictions from the traditional approach for a series of ternary CH4/CO2/N2 displacements.

Accurate tools for prediction of displacement performance in ECBM processes are instrumental in design and implementation of enhanced gas recovery schemes. The results and analysis presented in this paper, demonstrate that more sophisticated thermodynamic models must be used in ECBM simulators when mixtures of CO2 and N2 are used to displace CH4 from coalbeds.