bluuebunny/crossref_metadata_2025 huggingface dataset:
Recovery and Utilization of Methane from Solid Waste Landfills
Authors: Frantz J. H. , Wood Randy M. , Sawyer Walter K. , Delozier Denise L.
Published: December 2007

This paper will discuss new developments in recovery and utilization of methane from solid waste landfill projects in the United States. Landfills produce methane and CO2 gas (LFG) at 550 BTU/scf due to decomposition of biodegradable waste. The LFG recovery industry started in California in the 1970's and has continued to expand. During the 1970's and 1980's, LFG was used primarily as an energy source for direct onsite use such as boilers, electric generation, and co-generation. In the 1990's, many landfills began investigating upgrading LFG to pipeline quality, high BTU gas. LFG can be upgraded commercially to pipeline standards by removing the CO2 using adsorption, membrane separation, or cryogenic processes. This paper will review the historical uses of LFG, but focuses on the more recent efforts to process and upgrade LFG to high BTU, pipeline quality gas. Several case histories will be presented showing historical landfill gas rates, gas rate history matches using LFG reservoir models, and performance forecasts for future LFG rates. We will also discuss a methodology to develop a more robust simulation model to estimate landfill gas production.
Drilling and Completing a High-Angle Well With Coiled Tubing Technology
Authors: Samsonsen B. , Jacobsen B.G. , Skagestad T. , Kerr S.
Published: December 2007

In many cases the casing exit point of a CTD sidetrack may have to be established below the cap rock to avoid high pore pressures and thus excessive mud weights. If the target is attic oil updip from the mother well, it may become necessary to drill a tangent section with very high inclination.

In the case of A-19A on Gullfaks field a tangent section with 125 degrees inclination had to be drilled with the TD ten meters shallower than the casing window. The challenging wellpath was successfully drilled and is likely to increase the number of achievable targets for CTD in the Gullfaks field.

Focus in the planning phase was centered on friction and forces available and thorough simulations were performed by the contracting company. The conclusion was that the well could be drilled if the friction factor in open hole was no more than 0,4. The experience from first CTD sidetrack in this field was that the friction factor in open hole was less than 0,4 when tripping. However, differential sticking seriously impeded weight transfer while drilling.

A solids free drilling fluid was regarded as the best choice for improving weight transfer. No problems were observed due to differential sticking. Priority was also aimed at investing the necessary time for frequent wiper trips to enhance hole cleaning.

The planning and observations of the operational challenges encompassed during this CTD operation are discussed further in the contents of this paper.

P. 81
Goldsmith San Andres Unit CO2 Pilot - Design, Implementation, and Early Performance
Authors: Jasek D.E. , Frank J.R. , Mathis L.S. , Smith D.J.
Published: December 2007

This paper describes the evaluation, design, implementation, and operation of a large miscible CO2 tertiary pilot in the Goldsmith San Andres Unit (GSAU), Ector County, Texas.

The pilot consists of nine inverted (injector-centered) 5-spot patterns covering approximately 320 acres and is located in a mature area of the field where the majority of the wells had been plugged due to high water cuts. The pilot location was selected based on geology and reservoir performance during waterflood. A CO2 pilot was chosen, rather than full- field implementation, to investigate uncertainties associated with the CO2 target oil saturation, the feasibility of re-entering abandoned wellbores, and overall CO2 flood performance. CO2 injection in the pilot commenced in December of 1996.

The project benefited from available technology on CO2 flooding and particularly from information on other San Andres CO2 floods. The paper summarizes the methods used in the early project evaluation/design, data acquisition programs, reservoir simulation and CO2 flood predictions, and project implementation. The reservoir management plan, actual performance to date, and future potential are also discussed.

The process used (methodology and technical analysis) to evaluate and design the GSAU CO2 pilot are applicable to other potential Permian Basin CO2 floods.

P. 23
Vertical-Horizontal Wells For Depletion And Sweep
Authors: Muraikhi A.J. , Pham T.R. , Liu J.S. , Khatib M.R. , Muhaish A.S.
Published: December 2007

This paper discusses a completion scheme currently being applied in a thick, large, elongated carbonate anticline Middle-East oil reservoir. The new well completion calls for a combination of an open hole horizontal section penetrating the top 10 feet of the reservoir and a cased or un-disturbed vertical segment through a thick formation. The horizontal section will be used for producing and the vertical segment will be used for monitoring purposes (Figure-1). The cased vertical segment will allow undisturbed monitoring of the sweep in the area below the horizontal section, especially in areas of high heterogeneity. The horizontal application proved to be useful both in terms of economics and sweep with supported reservoir simulation results and some actual field data performance. Pilot wells have been drilled and completed and early assessment has been encouraging.

P. 123
Practical Methods Employed in Determining Permeability Anisotropy for Optimization of a Planned Waterflood of the Elfisk Field
Authors: Wade J.M. , Hough E.V. , Pedersen S.H.
Published: December 2007

This paper presents the various techniques and measurements undertaken to determine both the magnitude and direction of horizontal stress anisotropy present in the Eldfisk Field in preparation for a planned waterflood. Results from field measurements of in situ stress obtained from a vertical pilot hole designed specifically for gathering stress data reveal a highly an isotropic state of stress, with a maximum horizontal in situ stress oriented approximately 47 from grid North. These measurements include stress orientations measured from an elastic strain recovery (ASR) tests on core, oriented acoustic log data and 2 micro-frac tests with pre- and post fracture imaging log runs. Micro-fracture tests yield values of 5218 psi to 5326 psi for the minimum horizontal stress and 6904 psi to 7154 psi for the maximum horizontal stress. This represents a relatively large stress anisotropy which, in turn, could result in a sizeable permeability anisotropy. A numerical simulation study was conducted to investigate the impact of horizontal permeability an isotropy and completion strategy on hydrocarbon recovery. The results of this sensitivity study show that the optimum completion strategy consists of suitably staggered perforation schemes in the injection and producing wells.

P. 49
Model-Based Sticking Risk Assessment for Wireline Formation Testing Tools in the U.S. Gulf Coast
Authors: Underhill W.B. , Moore L. , Meeten G.H.
Published: December 2007

A model is developed to characterize wireline formation tester sticking from quantitative analyses of the most prevalent sticking modes. An appropriate description of differential pressure sticking mechanics for stationary logging tools and cables forms the foundation of the model, and a supplemental formulation provides a quantitative relationship for key-seat development based on borehole and tool parameters. The results of the analysis are converted into a sticking probability formula that allows quantitative risk assessment at the job planning stage. The primary form of the model uses mud cake parameters derived from a wellsite evaluation device, but an alternative formulation utilizes laboratory and field measurements of mudcake properties and only requires conventionally available parameters for risk assessment. The model is calibrated and tested by application to a database of 664 formation testing jobs in the Gulf Coast area. The resulting strong correlation between calculated sticking probability and actual fishing frequency illustrates the power of a model-based approach to risk assessment. In contrast to most statistically based approaches, it is possible to incorporate a large number of relevant parameters and quantitatively examine risk levels as adjustments are made. Direct measurement of mudcake properties at the wellsite will further enhance the risk assessment accuracy.

P. 79
A New Method for Analysis of Long-Term Pressure History
Authors: Gilly Patrick , Horne Roland N.
Published: December 2007

This study presents a new way to integrate flow rate history and pressure history data in well-test analysis. The method used is an extension of the deconvolution principle to a chosen period of time before the well-test. It is based on the recovery of missing parts of the pressure history by taking into account the flow rate history and the available sections of measured pressure history. The method has the advantage of working without making any assumption about the reservoir by using the data itself to define the "model". A real example with 71 pressure points and 70 corresponding flow rate points shows how it is possible to recover the first 20 pressure points correctly considering that only the flow rate history and the last 51 pressure points are known.

The main purpose of this procedure is to have an alternative to treat the problem of flow rate variations both before and during the well-test. In such a case, neither the deconvolution (only applicable for flow rate variations during the well-test, when flow rate and pressure are both known), nor the multirate superposition plots (too constraining on the shape of the flow rate history and on the late time reservoir behavior) can be applied properly.

In addition, the principle of the method enables us to extend its use to the analysis of well-tests with pressure recording errors or missing pressure recording. Examples show that it is possible to make a good analysis of a well-test with missing pressure regions when current methods give only parts of the information.

P. 91^
Combined Production Logging, Transient Testing, and Well-Performance Analysis
Authors: Kabir C.S. , Hoadley S.F. , Al-Dashti Q. , Kamal D. , Hasan A.R. , Lin D.
Published: December 2007

This study presents an approach to exploit full potentials of a production logging run. In the proposed methodology, we seek layer flow contributions, reservoir parameter estimation, and well-performance optimization, in one logging operation. In particular, we match the entire wellbore pressure, temperature, and density profiles using a fully transient wellbore/reservoir simulator.

In the proposed approach, perturbations can be created either from static or dynamic well condition. New formulations for these initial conditions for multirate tests with non-Darcy skin are presented. Field examples illustrate the notion presented in this work.

P. 107
Fully Coupled Analysis of Well Responses in Stress-Sensitive Reservoirs
Authors: Chin L.Y. , Raghavan R. , Thomas L.K.
Published: December 2007

A fully-coupled geomechanics and single-phase, fluid-flow model is developed to evaluate the combined effects of stress, fluid flow and reservoir property changes on well performance. In particular, we pay particular attention to the interpretation of pressure buildup tests and to changes in the production characteristics of wells. In general, for weak hydrocarbon reservoirs that exhibit nonlinear, elastic and plastic constitutive behaviors and stress-dependent properties such as permeability and porosity, the coupling effect may not be ignored in well test analysis. The coupled interaction between geomechanics and reservoir fluid production markedly affects the stress state and reservoir properties. Because we are using a coupled, numerical model, we evaluate the consequences of using simplified relationships (e.g., permeability as a function of pressure). Numerical analyses are performed to quantitatively assess the impact of reservoir stress-sensitivity on practical well test problems. The key variables investigated in the study, that are important in evaluating stress-sensitive reservoirs, include permeability, porosity, and constitutive behaviors of reservoir rock including hysteresis and loading conditions. The development of high-stress regions around wellbores and its consequences on well performance are considered. The numerical results from the study indicate that for analyzing highly stress-sensitive reservoirs, a fully-coupled geomechanics and fluid- flow modeling approach is necessary and the developed model employed in this study provides such a tool.

P. 127
Incorporation of Two-Phase Production Data into Reservoir Characterization
Authors: Ates Harun , Kelkar Mohan
Published: December 2007

In this study, two-phase production history data is incorporated into reservoir characterization by inverse modeling. As a first step, an analytical method has been developed to compute sensitivity coefficients for two-phase flow conditions. These equations are independent of flow simulators, and can be incorporated to any finite difference or streamline simulators. They only require one simulation run to compute the sensitivities for all time steps. In this study, we have chosen streamline simulation, which is order of magnitude faster than finite difference simulations. In the second step, a dual loop iteration technique is employed which uses conjugate gradient relaxation in order to bypass the explicit construction of the sensitivity coefficient matrix and the inversion of the product of sensitivity coefficient matrix and its transpose. Thus, a substantial reduction in the computational cost for solving the inverse problem is achieved, including the help of streamline simulation. Finally, this technique was validated using synthetic as well as field cases. The field case study was conducted on a sandstone reservoir.

P. 151
Sedimentary Interpretation of A Multilayered Clastic Oil Reservoir: Impact on Development Plans for the Zubair Reservoir, Raudhatain Field
Authors: Nemcsok S. , Morrison N.H. , Carruthers A. , Abdullah Sh.
Published: December 2007

The Lower Cretaceous Zubair reservoir is a major producing horizon in the Raudhatain Field of North Kuwait. The reservoir comprises a number of isolated vertical major sandstone units. With plans to significantly boost production through waterflooding, a major studies program has been conducted. A major sedimentology and reservoir description review has defined controls on reservoir quality, heterogeneity, and architecture. A new layering scheme has been established to honor the sedimentological boundaries and the associated dynamic reservoir behaviour.

Deposited primarily as estuarine channel sands, the Zubair reservoir shows a preferred west-east channel-fill geometry across a north-south paleo-shoreface. The understanding of this geometry is crucial in the selection of future drilling locations to meet both injection and production constraints. Four main flooding events during clastic deposition define the main producing units in a sequence stratigraphic framework. Four reservoir quality sandstones are present within the nine lithotypes identified. Channel incisions down into the underlying section by up to sixty feet create strong vertical connectivity in the main producing horizon in the Upper Zubair.

Integration of the static model, incorporating recently acquired 3D seismic, with the dynamic data has enabled an optimized development plan which incorporates both uncertainty and risk reduction. This plan will develop the field with peripheral water injection, supplementing the natural aquifer in some intervals. Dual wells will be used to maximize value. Historic gas injection and units at or around saturation pressure complicate the reservoir development. The occurrence of tar mats, identified by Iatroscan techniques, presents a further control on the selection of drainage and injection points.

P. 177
Integrating Seismic and Well Log Data. A Case Study from the Misoa Formation, Lake Maracaibo, Venezuela
Authors: Diyashev Iscander R. , Ayers Walter B. , Martin Ronald B. , Lopez Alejandro , Escorcia Florangel
Published: December 2007

This paper presents methods and results of the integration of 37km2 of 3D seismic data and 38 well logs from the VLE 196/Lamar Field, Block V of Lake Maracaibo. The goal of the study was to develop a geologic model using integration of seismic and well log data. Specifically we mapped reservoir properties using both seismic and well log data in the area that has good well control, and extrapolated porosity and thickness eastward, to encompass the area required for reservoir modeling but lacking well control, using seismic data alone.

P. 189
An Evaluation and Design Approach to Gravel-Pack Treatments in the Gullfaks field
Authors: Karlstad Simen , Sherlock-Willis Terri , Rajan Surya , Samsonsen Bianc , Monstad Per Arild
Published: December 2007

Wells in the Gullfaks field, situated in the Norwegian sector of the North Sea, are characterized by long, highly deviated producing intervals. Cased hole completions with 177.8 mm production liners are dominant, but since 1994 several wells have been completed as open hole in one or two intervals. The Gullfaks field is producing from a reservoir that consists of a multitude of high permeability loosely consolidated sandstone formations. Formation permeability varies from 50 md to as much as 10 darcies, while reservoir pressure ranges from 220 bar to 320 bar. Sand production from the loosely consolidated formations is prevented with traditional gravel-packs. Internal gravel-packs in the Gullfaks field are performed with under-balanced snubbing, thereby eliminating the need to kill the well at any stage of the operation. Leakoff in the different formation sands is well defined by log permeability and reservoir pressure; high choke pressure during the under-balanced operation aids in controlling the pre-determined return rate throughout the job.

This paper describes an approach where gravel-pack treatments pumped in the Gullfaks field have been designed and evaluated using a pseudo three-dimensional gravel placement simulator. With reservoir pressure given as a range rather than a specific value, a sensitivity study yielded the best estimate for reservoir pressure. Following verification of reservoir parameters and simulator capabilities, new jobs were optimally designed using the simulator so that potential pitfalls in traditional designs could be avoided. Designs were modified to achieve a successful annular pack, also permitting a priori knowledge of safe operational limits. This further allows better control over fluid selection, rate determination, tool position and other parameters that are critical to achieving a successful outcome of the treatment. Post-job evaluation of gravel-pack treatments using this approach confirms the validity of the designs.

Three wells in the Gullfaks field operated by Statoil, serve as the basis for the case studies presented in this paper. Recommendations are made on how to extend the technique to similar fields.

P. 149
Ultrasonics Technology: Creating a New Approach to Drill Cuttings Disposal
Authors: Glansbeek J.H.B. , Avern N.R. , Simpson D.T.
Published: December 2007

The use of ultrasonic technology to assist with the disposal of drill cuttings has been assessed as part of a larger environmental study. Ultrasonic technology allows particle sizes to be reduced, suitable to create a stable homogenous suspension which can be re-injected locally or easily conveyed and transported for disposal to another site. The significant size reduction achieved by ultrasonics also enables the dispersion of cuttings naturally into the water column when employing suitable biodegradable drilling fluids.

The results obtained from this project firstly demonstrate the size reduction capabilities (below 300 m) of ultrasound with various rock lithologies, different solids fluid loadings and the length of exposure time to the sonic waves. Secondly it showed that a stable slurry can be maintained enabling drill cuttings to be handled and transported to other disposal sites (onshore or offshore, legislation permitting) in suspension. This new approach compared to handling dry cuttings unlocks new opportunities with regards to cuttings re-injection and creates new dimensions for handling and transportation drill cuttings.

P. 199
The First Cuttings Injection Operation Worldwide in a Subsea Annulus: Equipment and Operational Experience
Authors: Saasen Arild , Bale Arthur , Corneliussen Rune , Kristiansen Per Bjarne , Oftedal Bjorn
Published: December 2007

The first cuttings re-injection operation in a subsea annulus is presented. A discussion of some important formation fracturing aspects is presented. The necessary equipment is described. This includes a description of the modified well head design for cuttings re-injection and description of a flexible hose transporting the re-injection slurry from the platform to the well head. A short description of the cuttings re-injection operation is given where cuttings were re-injected into the same well as being drilled.

P. 207
Handling, Treatment, and Disposal of Produced Water in the Offshore Oil Industry
Authors: Khatib Zara I.
Published: December 2007

Several liquid/liquid hydrocyclones and disc-stack centrifuges were evaluated to determine their performance in removing dispersed oil and to establish the domain of their operation. Results of pilot tests at the Westhollow Technology Center and the full-scale field trials in GOM are summarized. Based on these results, flow diagrams to integrate hydrocyclones and disc-stack centrifuges into a production separation facility are recommended. Best practices are also outlined to handle, treat, and dispose of produced water effectively.
Dehydration Field Tests on Draugen
Authors: Polderman H.G. , Hartog F.A. , Knaepen W.A.I. , Bouma J.S. , Li K.J.
Published: December 2007

Tests were carried out to investigate the potential of new Zeta Dynamics internals for the optimisation of the water handling capacity of the Draugen primary separators. To this end these new internals were installed in the Draugen test separator and an assessment was made of its separation performance before as well as after the installation.

Since the production at Draugen is still practically dry, the advent of water production was simulated by flowing heated seawater through the separator. The tests were carried out on the wellstream of one of the horizontal platform wells, and water was injected upstream of the choke valve using the high mixing intensity in the valve to disperse the water in the crude. The tests consisted of varying the crude and water flow, and measuring the distribution of water and oil upstream, inside and downstream of the separator, via sampling and radiological techniques.

It could be concluded that the modification of the separator internals has not led to an obvious breakthrough in separation performance. The new internals improve the flow distribution, as claimed by the vendor. This appears from the sharper interfaces in the tests after the modification, and from the reduced spread in the residence time distributions. However, the new inlet internal has a negative effect on the phase distribution of the incoming feed. This appears from the increasing mixing of gas, crude and water in the separator with increasing flowrate, this despite the simultaneously decreasing stability of the crude/water dispersion and the existing gas/liquid stratification at the inlet. It can be conjectured that the originally installed Shell 'Schoepentoeter' inlet gives less resistance to the flow and may even favour coalescence and preseparation due to centrifugal acceleration.

The test results show that the size of the water droplets at the inlet is correlated with the water concentration and the pressure drop over the choke valve. However, the correlation is different from the one established from laboratory experiments, which is probably due to the different degree of premixing in both cases.

The density profiles in the separator give evidence for the presence of a dispersion band, varying in size with process conditions. The predictions of separation efficiency as a function of flow rate and feed droplet size according to the SRTCA dispersion band expansion model (ref. SPE 38816) are in agreement with the test results.

Finally the future dehydration capacity of the Draugen installation was estimated by combining the validated separation efficiency correlations with calculations of the droplet size expected at the prevailing operating conditions.

P. 121
Modeling Heavily Faulted Reservoirs
Authors: Heinemann Z. E. , Heinemann G. F. , Tranta B. M.
Published: December 2007

The gap between a geological reservoir model and its numerical simulation model increased rapidly in the last decade. Due to 3D seismic and other highly sophisticated techniques the geological model can now account for normal and reverse slanted faults, high permeability channels, discontinuities, etc. down to a resolution of 10x10x1 feet. The reservoir can be represented by 100 million grid points and include accurate positioning of 3D faults and other surfaces. In a simulation grid the faults are conventionally represented by the Cartesian, corner point or curvilinear grid block boundaries. In this way only few faults can be handled and even then, they are inaccurately modeled. It is therefore not possible to model a heavily faulted reservoir with conventional methods.

The paper presents a new concept and a fully developed solution to this problem. The fundamental difference between this method and all previous ones is that the faults are regarded as inner boundaries and the flow equation will not be used to calculate the fluid transfer through these surfaces but instead it will be handled by boundary conditions. The concept allows the automatic alignment of the grid in a heavily faulted reservoir. The location of the grid points is not changed and only the shape of grid blocks along the fault traces is modified. The method is applicable for Cartesian as well as kPEBI (perpendicular bisection grid with full permeability tensor) grids. The mathematical basis of the gridding and the fault construction methods were already published1,2,3. This paper presents the implementation in industrially used simulator(s) and shows the advantages of the new method. The practical applicability is demonstrated by 2 case studies. The first one is the 2000 km2 Aderklaa conglomerate containing several oil and gas fields. The second is a slanted well traversing several reverse faults.
Field Simulation of Naturally Fractured Reservoirs Using Effective Permeabilities Derived From Realistic Fracture Characterization
Authors: Jensen C.L. , Lee S.H. , Milliken W.J. , Kamath J. , Narr W. , Wu H. , Davies J.P.
Published: December 2007

In this paper, we describe field application of our recently published boundary element and simulation methods to account for flow in naturally fractured reservoirs. We apply our methods to modeling Carter Knox and Rangely Fields, both onshore fractured reservoirs in North America. Carter Knox is a tight-gas reservoir undergoing primary depletion, and Rangely is a mature reservoir undergoing tertiary oil recovery.

Our method uses explicit and complex fracture geometries generated for the entire field area of interest. Effective permeability tensors at the grid-block scale are generated by accurately calculating coupled matrix and fracture flow. The effective permeabilities reflect the enhanced and directional flow effects created by the presence of fractures that may not be oriented orthogonally to the simulation grid. A finite-difference reservoir simulator, enhanced to account for tensor permeability input, is used to model field performance.

Because the model includes all available geologic and well features (such as natural and induced fractures), ad hoc changes to original geological input during history matching are reduced. Using this improved history-match model allows for improved prediction of reservoir performance. P. 157
Effects Of Discontinuous Shales On Multi-zone Steamflood Performance In The Kern River Field
Authors: Williams L. Lee , Fong William S. , Kumar Mridul
Published: December 2007

Steamflood performance of the Monte Cristo I lease in the Kern River field was analyzed in this study. A detailed, 18-pattern, heterogeneous model incorporating all reservoir zones was developed to simulate over 21 years of field response and predict future performance. Results were used to improve reservoir management, quantify the impact of discontinuous shales on oil recovery from individual zones, determine inter- zone gravity drainage, and identify bypassed oil zones for future infill drilling.

Results show that detailed modeling provides a more realistic description of actual performance and that small, pattern- element or single-sand models used in previous steamflood studies are inadequate for such reservoirs. Calculated oil recovery and temperature profiles compare well with field data. Discontinuous shales allow significant oil drainage to occur from the upper to the lower sands. As a result, the upper. unsteamed zones contain less reserves than expected. On the other hand, the lower zones continue to produce long after steam injection into the zone has stopped, giving high apparent recovery. The multi-pattern, heterogeneous model may be also used to identify bypassed zones for future in-fill drilling.

P. 267
Geostatistical Analysis of Petrophysical Data and Modeling of Fluid-Flow Effects in
Authors: Jennings James W. , Ruppel Stephen C. , Ward W. Bruce
Published: December 2007

Permeability data from Permian dolomitized shallow-water platform carbonate outcrops in West Texas and New Mexico document extreme, short-range variability, vertical inter-bed average permeability contrasts, 140–180 ft [42–54 m] lateral periodicities, and up to 2,700-ft [810-m] lateral trends. The short-range heterogeneities can be modeled with K-Bessel semivariograms having asymptotic power-law behavior at the origin. The periodicities can be modeled with "hole-effect" J-Bessel semivariograms. Most of the variance within single grainstone units is concentrated in the first few feet [1 or 2 m]. Variabilities within grainstone beds are larger than contrasts in average permeability between beds.

Stochastic 2-D areal and vertical cross-section models explore the effects of these heterogeneities. Simple tracer simulations demonstrate that some long-range features control overall flow behavior even when short-range variability composes most of the variance. The short-range heterogeneities produce local smearing of tracer fronts.

P. 305
E & P; Old and New Forecasting Issues
Authors: Soendenaa E. , Haldorsen H.H.
Published: December 2007

A production forecast is real enough, but making it is still 'real magic'. Why? Because when making it, we still have to quantify rocks we have not measured properly and assume, or even ignore a large number of future events (oil price, technology development, etc) which may later affect it ('magic'). Hence, concepts like uncertainty, risk, grisk (= the possibility of exceeding expectations) and probability are introduced to be able to communicate about uncertain forecasts with a quantitative language.

25 years of North Sea forecasting has given oil companies and exploration and production (E&P) -professionals invaluable experience. A large number of surprises, both positive and negative have educated everyone involved. This paper will address some of the lessons learnt and the dramatic improvements in E&P-tools and work processes over the years.

Communication and co-operation among disciplines, projects, companies etc. are discussed from the viewpoint of 1) passing on error bars, 2) learning, 3) the value of diversity and 4) optimal decision-making to achieve success (success = 'running well' (high production regularity) on 'well-chosen roads' (development concept)).

Lastly, future forecasting challenges and 'new' forecasting issues are discussed; anticipating new technology, smaller, deeper and more complex fields, deep-water fields, new types of wells, etc.

In general, without production forecasts, the E&P-industry comes to a grinding halt. Without reliable forecasts, no optimal decisions can be made. Some of the best minds in the nation devote their talent to E&P forecasting under uncertainty. Top management is totally dependent on their creativity, competence and good judgement. For this reason, the 'technical ladder' should be a real and attractive career alternative. Predicting the unpredictable is a job, which demands considerable respect. Some say its pure luck if we are spot on with our forecasts. The funny thing is that the more we practice and the more experience we gain the 'luckier' we seem to get!

P. 157
Simulation with a Full Tensor Coefficient velocity Field Recovered From a Diagonal Tensor Solution
Authors: Edwards Michael G.
Published: December 2007

Commercial simulators generally assume that the pressure equation always has a diagonal tensor permeability field. However, cases that involve the use of non-Cartesian grids, cross-bedding or upscaling (or any combination there-of) will give rise to a full tensor coefficient velocity field. Discretization of a full tensor increases the scheme stencil, simulation cost, and complexity of implementation. The focus of this paper is on the development of fully implicit finite volume schemes that can allow full tensor fluxes while retaining standard matrix inversion.

P. 383
Laboratory Design and Field Implementation of Microbial Profile Modification Process
Authors: Lee Hae Ok , Bae Jae H. , Hejl Keith , Edwards Aimee
Published: December 2007

A microbial profile modification process consisting of sequential injection of spores and nutrient was designed and field tested in Eunice Monument South Unit, a carbonate reservoir, in Lea County, New Mexico. Laboratory work involved testing of microbial activity in reservoir brine, nutrient optimization, and design of spore and nutrient concentration and size. An 80-acre, inverted five-spot pattern was used in this field trial. The pre-treatment injection profile in the central injector showed the presence of two thief zones, which were taking 42% and 58% of injected water. 16,000 barrels of spore suspension in the concentration of 108 cfu/mL (colony forming unit per mL) was injected for 16 days, followed by the injection of 14,000 barrels of nutrient solution. Prior to microbial treatment, the water injection rate was 1000 bbls/day at 30 psi at the header, whereas the post treatment injection rate was 500 bbls/day at 650 psi. Several post-treatment injection profiles up to 8 months after the treatment, showed almost complete fluid diversion and good stability of the in-situ formed biofilm. P. 393
Evaluating Fracture Stimulation Treatments in Northern Mexico by Integrated Reservoir and Fracture Treatment Analysis
Authors: Robinson B.M. , Rascon Austreberto Rios , Hernandez Crescenciano Perez , Sanchez Bujanos Juan M.
Published: December 2007

Several studies have been performed recently that have focused on reevaluating the original fracture treatment designs performed in various low permeability gas fields in the Burgos Basin of northern Mexico. The primary goal of these studies was to determine if the fracture treatments were achieving optimal stimulation of the reservoirs. Results of this work have indicated that the propped fracture half-lengths achieved in the past are approximately 40% to 50% of the original designed half-lengths. The main reason for the shorter fracture lengths is that the created fracture heights were greater than expected.

The studies have provided better descriptions of individual reservoir properties and vertical stress profiles. These results are now being used in both reservoir and fracture models to design more optimal fracture treatments. These new fracture treatment designs have increased production from 50% to 300% over previous fracture designs.

P. 415
Hydraulic Fracture Stimulation Design and Well Performance in Nonconventional Reservoirs
Authors: Conway Michael W. , Barree Robert D.
Published: December 2007

In recent years there have been numerous reports of the application of state-of-the-art methodologies to hydraulic fracture treatment design. One of the biggest problems in applying advanced technology to stimulation design is the acquisition of input data for computer simulations.

Over the course of the last three years, a cost effective systematic methodology has been developed for acquiring the reservoir properties required for hydraulic fracture treatment design. Dipole sonic logs coupled with a water injection/fall-off test in combination with a 3-D hydraulic fracture design simulator have been used to understand reservoir characteristics and to design stimulation treatments based on reservoir characteristics.

This methodology has been applied to conventional tight gas reservoirs as well as coalbed methane reservoirs, and has allowed the optimization of the stimulation treatment based on reservoir characteristics. There are numerous examples of successfully completed stimulation treatments that have failed to produce. This paper recounts examples for both coalbed methane and conventional reservoirs where the treatment type can be compared to reservoir characteristics and production responses.

P. 421
Simplified Productivity Equations for Horizontal Wells Producing at Constant Rate and Constant Pressure
Authors: Helmy M. Wael , Wattenbarger R.A.
Published: December 2007

This paper presents a simple model to calculate the productivity of horizontal wells producing at constant flowing bottomhole pressure, Pwf, or constant rate from bounded reservoirs. We propose new, easy-to-use correlations to calculate the shape factor and partial penetration skin for both cases. The shape factor is calculated using an analytical solution of a fully penetrating well; and the partial penetration skin is calculated using a numerical solution. The correlations are developed using nonlinear regression (with R2 of 99%) of more than 800 numerical simulation runs for different reservoir aspect ratios, well locations and well penetration ratios. The productivity of wells producing at constant Pwf can be quite different from that of wells producing at constant rate. The models proposed in this paper are only approximate. In many cases they proved to be more accurate than other methods currently available in the industry. However, errors could be generated when the proposed models are used outside the range of applicability of the correlations.

P. 379
Optimization of Stimulation Chemistry for Openhole Horizontal Wells
Authors: Morgenthaler L.N. , McNeil R.I , Faircloth R.J. , Collins A.L. , Davis C.L.
Published: December 2007

Successful completion of openhole horizontal wells requires removal of potential impairment from the near wellbore and formation face. Impairment can reduce well productivity and lead to failure of sand control screens due to plugging and erosion. Shell has adopted the practice in the Gulf of Mexico of employing drill-in fluids with acid soluble bridging, and weighting agents for all openhole drilling and extensive displacement and acid cleanup procedures during horizontal well completions. Drill-in fluid and filtercakes are removed with specially formulated sweeps and by attainment of sufficient velocity to achieve effective displacement. Filtercakes are removed with specially formulated washes applied using washcups or coil tubing to ensure that cleanup formulations contact filtercake materials.

Drill-in fluids and clean-up systems must be specially formulated arid evaluated for specific applications. We have adopted a suite of laboratory screening tests to evaluate formation damage and removal chemistries to ensure that each well is effectively cleaned. These tests can also be used to evaluate new fluid systems before taking them to the field. Our approach in this instance is to compare data from new fluids to results obtained with fluids we have a successful field track record with. In this paper we will review these procedures arid results with results with a variety of fluid systems.

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New Water-Soluble Perforation Ball Sealers Provide Enhanced Diversion in Well Completions
Authors: Bilden Dean M. , Lacy Lewis L. , Seiler Fred H. , Ischy Noel D. , Fox Craig S.
Published: December 2007

A new water-soluble perforation ball sealer has been developed and successfully used as a substitute for conventional ball sealers. They also can and have been used in situations where conventional ball sealers would not be an option due to the potential of creating undesired costly workover operations.

The introduction of a degradable or water-soluble ball sealer signifies a major breakthrough in ball sealer technology. This paper discusses the new ball sealer chemical and physical properties and development methodology. Laboratory testing techniques and methods are presented.

This paper focuses on the laboratory testing conducted during the development phase and the data generated to support proper application in the field. Also, the potential benefits of water-soluble ball sealers are presented along with examples of successful application in wells.

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Proppants, We Still Don't Need No Proppants - A Perspective of Several Operators
Authors: Walker Ray N. , Hunter Jeffery L. , Brake Al C. , Fagin Paul A. , Steinsberger Nick
Published: December 2007

In SPE 38611 "Proppants, We Don't Need No Proppants" data showed that fracture treatments using treated water and very low proppant concentrations (waterfracs) were very successful in the East Texas Cotton Valley sandstone. The paper presented limited initial results from one operator in one field. Following this paper a more comprehensive set of production comparisons of wells completed with standard frac jobs and waterfracs since 1996 for several different operators in the East Texas area are presented. Analysis of offset comparisons, economics, and other benefits are described from the aspect of several different operators.

Conclusions will point out the cost savings and the ability to exploit marginal reserves with this technique. There will also be a perspective from each operator. The waterfrac technique has led to widespread discussions among many operators in various tight gas plays. Many operators are experimenting with the technique and experiencing excellent results. This technique is a major contribution to the reduction in completion costs in wells that must be hydraulically fractured. The industry has experienced a major inflation of well construction costs and this technique will be of paramount importance in our efforts to keep costs down in order to continue to develop tight gas reserves. Techniques such as these require many months of production in order to analyze to determine the actual results. Several techniques and the perspectives of several operators and how they make these important decisions will be presented here.

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Optimized Hydraulic Fracturing Improves Oil Production in the N'Dola Field, Offshore Angola
Authors: Bagzis John M. , Wehunt C. Dean , Neubauer Edward B. , Jansson Raymond P. , Tjoonk Richard , Roueche Lee N. , Scarborough Ben
Published: December 2007

Conventional hydraulic fracturing has been widely used to improve production within low permeability formations for the past 50 years. However, it is not as widely known for improving production within more moderate permeability formations. This paper pertains to the use of hydraulic fracturing in one such formation, the Pinda Sandstone, within the North N’Dola field, offshore Angola.

Hydraulic fracturing within this field was optimized utilizing advances in fracturing treatment technology for these deviated wells. These advances include using various point-source perforating schemes and proppant slugs to mitigate the creation of multiple fractures and near wellbore friction problems. These perforating schemes are compared as to length of perforated interval, shot phasing, number of shots per foot, and gun diameter. Also, proppant slug sizes and concentrations are discussed as to relative benefits in mitigating near wellbore problems associated with fracturing of deviated wells. Real-time data acquisition and analysis, including step-down testing, were included as part of the optimization process. Thirteen of the 15 fracturing treatments incorporated a live annulus for pressure monitoring purposes. Minifracs were utilized on every fracturing interval as a combination fluid efficiency test, fracturing model confirmation, and to carry the proppant slugs. Computer processed, stress logs were successfully used as an aid in selecting intervals with lower fracture initiation pressures. A continuously mixed, high-temperature, borate crosslinked, fracturing gel made from seawater was successfully employed. Also, a high temperature, encapsulated scale inhibitor was also used to control scaling problems that have plagued offsetting fields.

Production clean up procedures are discussed including the production ramp up procedures to mitigate proppant flow back, and the use of a hydrocylone desanding unit for proppant removal at the surface. This paper will also discuss the logistical challenges that this project created including the use of skid mounted, fracturing equipment and materials offshore aboard a tender rig.
Field Hydraulic Tests Improve HPHT Drillng Safety and Performance
Authors: Isambourg P. , Bertin D. , Brangetto M.
Published: December 2007

For the Elgin-Franklin UKCS fields, drilling of the HPHT phase is critical due to the narrow margin between formation pore and fracturation pressures. This problem is accentuated by the extreme temperature (up to 205C - 400F) and pressure (up to 1200 bar - 17400 psi). A new generation of down-hole Pressure While Drilling (PWD) tools allows a better real-time monitoring of the bottom-hole pressure, but cannot withstand the extreme temperature of the entire HPHT phase. Furthermore, down-hole and surface pressures are dependent on complex hydraulic phenomena which make predictions challenging. Consequently it was decided to perform hydraulic tests before drilling the HPHT section of the well 22/3Oc-G4 (first Elgin development well), in order to quantify the surface and down-hole pressures and temperatures on several operating conditions: circulating (with an without pipe rotation), tripping and flow check. Gelation tests, trapped pressure as well as pressure transmission tests were also performed.

Objectives of these tests were: to better understand some complex down-hole physical phenomena, to prepare practical guidelines (such as mud density variations, Equivalent Static Density values, ECD function of flow rate and pipe rotation, mud compressibility values, tripping procedures, etc…) before drilling HPHT sections, to check reliability and accuracy of new Real Time PWD tools, and to collect accurate well data for further hydraulic software packages validation or improvement.

These procedures led to great benefits, both in terms of safety and performance, when drilling the HPHT phases of the well: results were considered as highly positive. This paper details down-hole measurement procedures and results, operational guide lines, tools performances, lessons learnt, and explain how to cope with sources of possible discrepancies between actual values and software predictions.

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