bluuebunny/crossref_metadata_2025 huggingface dataset:
Continuously Tapered Coiled Tubing
Authors: Stanley Roderic K. , Martin John R.
Published: December 2007

Coiled Oilfield Tubing (CT) continually finds new markets, and has experienced continued growth in extended reach wells and high-pressure service. One major improvement is in the quality possible at skelp end welds, when continuously tapered strip1 is employed to join strip of the same thickness. In this paper, the following are discussed: Tapered strip and tubing dimensional specifications at all points along the tubing.Design of CT employing continuously tapered strips.Effect of tapered wall thickness on theoretical fatigue life.Effect of skelp-end welds of the same thickness, as compared with those of conventional tapering, on overall string life.Suggested amount of tubing to be removed if needed during servicing operations.
Propellant Assisted Perforating -- An Effective Method for Reducing Formation Damage When Perforating
Authors: Cuthill David A.
Published: December 2007

During the completion of a well the utilization of a propellant stimulation system immediately after or at the time of perforating has been demonstrated to provide sufficient stimulation energy to cleanup formation damage in the near wellbore region while remaining within the desired zone of interest. The focussed and virtually instantaneous nature of this technique means that it can be used in applications where more aggressive stimulation techniques may result in the increase of undesirable fluid production due to stimulation extension into adjoining regions. Propellant stimulation devices provide an inexpensive and effective method of dealing with near wellbore damage due to drilling, completion, or perforating in both producing and injecting environments.

Standalone propellant stimulation techniques have been successfully utilized for a number of years in various areas of the world. The recent development of a propellant assisted perforating system means that the perforations and near wellbore region can be effectively stimulated at the instance of perforating. This advanced perforating system fuses perforating and propellant stimulation devices into a hybrid system - the well can be perforated and the near wellbore region stimulated all with one run in the hole. The development of propellant stimulation modeling software and high-speed electronic pressure recording devices has assisted in the development and verification of the technique's effectiveness in removing or reducing near wellbore damage.

This paper will discuss the development history of this unique perforating and stimulation technique and the new analytical tools used in its advancement and ongoing application. A number of case histories are presented documenting the use and effectiveness of the stimulation method in a variety of environments and applications.
Fracture Propagation in Drill Cuttings Re-Injection: An Investigation Using Analytical Modelling
Authors: Deloge P-A. , Bouteca M. J.
Published: December 2007

Re-injection of drill cuttings is considered in several areas as a mean of disposing solid wastes. Injection in sands or in shales has been considered. In sands, fracture mechanics as used in hydraulic fracturing should apply. A new problem arises in shales where the stress contrast no more contains the fracture and a vertical propagation is expected. In this paper, we derive analytical solutions of the vertical propagation problem in order to better analyze the stability/unstability of fracture propagation. The shape of the fracture is assumed to be elliptical in the propagation plane and the ellipticity is obtained as a solution of the mechanical problem. The case of a circular fracture is firstly considered in order to analyze and illustrate the implication of the evolution of the minor horizontal stress as a function of depth. Considerations on the influence of the spatial discretization in numerical modelling are derived. The elliptical fracture is then dealt with. Finally, the case of a variable Young modulus is considered and the analytical solution is compared with numerical results obtained in the literature with the Terrafrac model. The analytical solution and the numerical one are similar for the case considered by BP.
Possible Use of Bacteria/Steam to Treat Asphaltene Deposition in Carbonate Rocks
Authors: Almehaideb Reyadh A. , Zekri Abdulrazag Y.
Published: December 2007

In this project bacteria and steam were tested to stimulate limestone cores damaged by asphaltene deposition. Several dynamic experiments were conducted to determine the effect of asphaltene on the permeability of limestone cores. Plugging effects due to asphaltene deposition were evaluated through a comparison between permeability measurements after oil flow and the reference permeability measured prior to oil flow. Damaged cores were subjected to bacteria and/or steam and the permeability of the cores was measured after each treatment. Core impairment resulting from in-situ asphaltene deposition was found to cause a 56 to 89% loss of initial oil permeability depending on rock permeability and injection rate. Core stimulation results from direct bacteria treatment, was found to cause a 3 to 105% improvement on the damaged core permeability depending on core permeability and the extent of the damage. Bacteria treatment results were compared to steam treatment of the damaged cores.
How Good Are Your Horizontal Wells?
Authors: Levitan M. M. , Clay P. L. , Gilchrist J. M.
Published: December 2007

This paper presents results of comprehensive analysis of BP horizontal well productivity and completion performance data. The study was performed to benchmark performance of existing horizontal wells with a view of developing simple empirical techniques that could be used for predicting performance of future wells. The developed correlation predicts a range of expected well productivity for future wells. This prediction reflects limitations of current completion technology and possible reservoir heterogeneities. The analysis method is based on presenting the existing well productivity data in the form of dimensionless parameters: the well productivity coefficient and the normalized productivity improvement factor. The results of this study can be used to: sense check estimate of theoretical well performance for undeveloped discoveries with historical performance for similar type reservoirsprovide quality control for newly commissioned wells to see if performance is as expectedhelp optimize development well design (i.e. high angle vs. conventional) to optimize reservoir exploitationoffer a means to rank well surveillance work based on where initial well performance lay with respect to global historic experience.
Visual Observation of Produced Water Re-Injection Under Laboratory Conditions
Authors: Al-Abduwani F. A. H. , van den Broek W. M. G. T. , Currie P. K.
Published: December 2007

Produced water re-injection is one of the most attractive produced water disposal methods both economically and environmentally, especially for offshore rigs. However, the main problem associated with PWRI is the unpredictable nature of injectivity decline.

In this paper a few of the basic experimental techniques used in assessing the damage inflicted upon sandstone samples are reviewed. Also a new experimental design is proposed, that is believed to add further insight to the ongoing research in this topic.
Water Shut Off in Gas Wells: Is there Scope for a Chemical Treatment?
Authors: Ligthelm D. J.
Published: December 2007

Water producing gas wells may suffer from liquid loading and get killed or their water production may exceed the capacity of the water handling facilities. Just closing off the water producing zone may be unacceptable if they have a large contribution to the gas production. A near well bore chemical treatment using a polymer solution is an option to reduce the water production and maintain the gas production. Once adsorbed to reservoir rock, the polymer may significantly reduce the relative permeability to water in the near well bore area.

Hundreds of gas wells of the Nederlandse Aardolie Maatschappij (The Netherlands) suffer from water production. A simulation study using a radial single well model was carried out to look after the feasibility of a treatment.

The study shows that a treatment based on reduction of the water relative permeability causes a choke effect: both the water and gas flow rates are reduced instead of only the water rate. Moreover, the benefits of a treatment are tempered because of a clean-up effect after injection of the chemicals. A reduction in the water/gas ratio by a factor 2 requires a reduction in the water relative permeability by at least a factor 10.

A well which was killed due to liquid loading at a high water/gas ratio and with a high contribution to the gas production by the water producing interval is a suitable candidate for treatment.

A treatment may also be considered for a well of which the water production exceeds the capacity of the water handling facilities. Provided that the flowing tubing head pressure can be significantly lowered, the loss of gas production from the water producing zone can be compensated by increased gas production from the other intervals.
A Pore-Network Model of In-Situ Combustion in Porous Media
Authors: Lu Chuan , Yortsos Yannis C.
Published: December 2007

In-situ combustion in porous media find applications in a variety of problems. Existing models to date are based on a continuum description, in which effective porous media are used. In this paper, we consider the use of dual pore networks (pores and solid sites) for modeling the effect of the microstructure on combustion processes in porous media. The model accounts for flow and transport of the gas phase in the porespace, where convection predominates, and for heat transfer by conduction in the solid phase. Gas phase flow in the pores and throats is governed by Darcy's law. Heterogeneous combustion with one-step finite kinetics is assumed at the pore walls. The time-dependent problem is solved numerically using a fully implicit scheme. The validity of the model is tested against existing 1-D solutions, in which three types of combustion patterns arise, depending on the value of a dimensionless parameter related to the ratio of heat capacities. Then, we report on 2-D simulations for forward combustion. The development of sustained front propagation is studied as a function of various parameters, which include heat losses, instabilities, a correlated porespace and the distribution of fuel. Implications of the findings for continuum models are discussed.
A New Modeling Approach for Heavy Oil Flow in Porous Media
Authors: Kamp A. M. , Joseph D. D. , Bai R.
Published: December 2007

Typical gas relative permeability measured during primary depletion of sand packs filled with heavy oil is in the order of 1E-6 - 1E-5. This is much lower than what is found in similar experiments with light oil. We think that the reason for this difference is that in heavy oil depletion, free gas flows in the form of small bubbles (dispersed flow) and not as connected gas. For dispersed flow, the velocity of the gas phase would not be inversely proportional to the gas viscosity, as would result from applying conventional Darcy's law.

This discrepancy indicates that a different type of model might be needed. We suggest the use of effective phase viscosities that should replace the relative permeabilities. We study a special case, in which the velocities of oil and gas are supposed to be equal. This leads to a model with one continuity equation and a Darcy law for the gas-oil mixture, depending on one effective viscosity.

We solve the model for steady flow in a core, obtaining good agreement with experimental measurements. Matching experimental data, an expression for the effective viscosity is obtained. The model is a first step in an attempt to obtain a new model for viscous gas-liquid flows in porous media. Such a model would reduce the uncertainty in forecasts of the oil production and recovery factors in heavy oil reservoirs such as the Venezuelan Orinoco belt.
Quantitative Analysis of Deliverability, Decline Curve, and Pressure Tests in CO2 Rich Reservoirs
Authors: Jokhio Sarfraz A. , Tiab Djebbar , Escobar Freddy H.
Published: December 2007

This paper investigates the effect of higher concentrations (0- 100%) of CO2, H2S, and N2 on natural gas well deliverability, reserve estimation, and pressure test analysis quantitatively. Physical properties of natural gases such as viscosity and compressibility are corrected according to the concentrations of the contaminant gases such as CO2, N2, and H2S present in it. These contaminant gases have profound impact on pressure test analysis. The Carr et all1 viscosity correction chart allows adjusting the viscosity up to 15% concentration of these contaminant gases. However, Wichert and Aziz2 compressibility correction chart allows up to 80% concentration of the CO2 and H2S.

Tiab3 developed an analytical method to estimate pseudopressure function for 0-100% combined-concentration of CO2, H2S, and N2. His pseudopressure was first re-plotted to simplify the procedure and then it was used to analyze the deliverability, pressure tests, and decline curves quantitatively. The analysis was performed with Carr et all1 viscosity correction chart, pure CO2 properties, and then with Tiab’s corrected pseudopressure. Pure CO2 properties were used due to the fact that the sample data has 98.256% CO2.

During this study it was observed that the compressibility factor has a little effect on analysis since it is a volume- related property. Viscosity, however, has the largest effect on the analysis since pressure is transmitted through the fluid in the porous media and viscosity works against it. It was also observed that the numerical method of calculating pseudopressure function introduced successive error in the analysis. Number of pressure data points also contributed to the error in numerical integration of the pseudo- pressure function.

Analysis of field as well as simulated examples resulted an absolute error range of 13-75% in the permeability estimation in pressure tests, 77% in deliverability tests, and 20-95% with pressure derivative. Error in AOF was observed as 15% and as high as 32 % in reserve estimation.
Paraffin-Crystal-Modifier Studies in Field and Laboratory
Authors: Becker J. R.
Published: December 2007

Crystal modifier chemistry is fast becoming very important in the enhanced production capacity of crude oil fluids. These products have been used for many years in offshore and refinery applications with a high degree of success. However, the broad usage of these chemicals in production areas has been spotty at best and often underutilized. Because of the incentive of increased fluid production resulting from crystal modifier application, producers have been more receptive to the usage of these types of treatment chemical applications. Considering this increased willingness of producers to incorporate these chemicals in their treating chemical programs it was important to study the various application methods by which these products can be introduced into the systems requiring treatment. Since, not all wells are equipped with capillary injection strings, or have backside access to chemical injection other methods such as squeeze applications are considered. Thus, laboratory testing and field test results are discussed in this paper.
Applications of the Transient Hyperbolic Exponent
Authors: Spivey J. P. , Frantz J. H. , Williamson J. R. , Sawyer W. K.
Published: December 2007

This paper introduces the concept of the transient hyperbolic exponent b. The transient hyperbolic exponent may be used to derive values for b for use in Arps' equations for a variety of drive mechanisms. For a coalbed methane reservoir, b is shown to be a function of the ratio of the average reservoir pressure to the Langmuir pressure, with b approaching 1.5 at pressures much higher than pL, 1.0 when the pressure is equal to pL, and approaching 0.5 at pressures much lower than pL. For wells producing from finite, transient dual porosity reservoirs, the b value may be as high as 2, during a flow period characterized by steady state flow in the natural fracture system, and transient linear flow in the matrix. A coalbed methane well and two Antrim Shale wells are presented as examples.
Neural Network Analysis Identifies Production Enhancement Opportunities in the Kaybob Field
Authors: McNichol Joanne L. , Getzlaf Don A. , Protz Myron
Published: December 2007

Evaluating and optimizing well completion procedures can be difficult because of the complexity of reservoir and completion dynamics. Although a vast amount of data is available within the industry, we need to analyze this data to enhance our ability to improve well economics. In this paper, we discuss the use of an artificial neural network (ANN) as a tool to evaluate and optimize stimulation methods and to develop a prediction model for three specific producing formations in the Kaybob field of northwestern Alberta, Canada.

The area is gas prone, with multiple producing horizons. Significant amounts of gas have been produced from the Bluesky, Cadomin, and Gething formations. Permeability is typically low, and hydraulic fracturing is required for economic production. Fracture treatment designs have varied considerably, with no apparent consensus as to the optimum fracturing fluid, proppant type, or treatment volume.
Log Examples with a Prototype Three-Detector Pulsed-Neutron System for Measurement of Cased-Hole Neutron and Density Porosities
Authors: Odom Richard C. , Wilson Robert D. , Ladtkow Richard K.
Published: December 2007

Recent publications1,2,3,4,5 have described the development and utility of cased-hole neutron and density porosity measurements from a pulsed-neutron system. Porosity information from cased-hole logging can provide required data for wells with limited logging programs such as old wells or new wells where open-hole logging is not viable. In reservoir sequences typical of the Rocky Mountain region, the addition of the cased-hole density measurement has proven useful in discriminating tight porosity from gas-filled porosity and coals from shales.

Whereas a tool such as the Computalog PND-S™ pulsed-neutron system uses two detectors, analysis of pulsed-neutron density measurement physics immediately suggests that a third long-spaced detector would be helpful in measuring deeper into the formation. Thus, a prototypical system based on the standard PND-S™ was constructed with a third detector at a 95-cm spacing. This prototype provided a collection of third detector data on normal logging runs.

Log examples from the North America Rocky Mountain region demonstrate the utility of this measurement in cased-reservoir analysis.
The Effect of Fracture Conductivity and Fracture Storativity on Relative Permeability in Dual Porosity Reservoir
Authors: Ahriche Imed , Tiab Djebbar
Published: December 2007

Relative permeability is one of the most significant parameters used in reservoir engineering simulation. It has been extensively investigated in homogeneous porous media. However, research on relative permeability in naturally fractured reservoirs is still limited. Because of laboratory limitations, simulation of naturally fractured reservoirs uses zero matrix-fracture capillary pressure, linear relative permeability with saturation, and neglects the effect of fracture conductivity and fracture storativity. The main objective of this study is to investigate the effect of these two parameters on relative permeability in naturally fractured reservoirs.

Single fracture system is made with different fracture characteristics such as porosity, permeability and fracture width using saw-cut Berea sandstone core samples with metallic plates. The centrifuge method is used to determine water-oil capillary pressure and relative permeability. For water-gas measurements, the parallel plate method is used.

Capillary pressure and relative permeability curves for different models were obtained and analyzed. A representative correlation between fracture absolute permeability and fracture aperture is obtained. The effect of dual porosity is well observed on the capillary pressure and relative permeability curves for both oil-water and gas-water systems. Thus, both capillary and viscous forces dominate the displacement of fluids in naturally fractured reservoirs. Fracture storativity has a negligible effect on the relative permeability as compared tofracture conductivity effect.
Combining Gradual Deformation and Upscaling Techniques for Direct Conditioning of Fine Scale Reservoir Models to Dynamic Data
Authors: Mezghani Mokhlès , Roggero Frédéric
Published: December 2007

Integration of dynamic data typically requires the solution of an inverse problem that can be computationally intensive and practically infeasible for fine scale reservoir models. In this paper we present a new methodology to directly update fine scale geostatistically-based reservoir models by combining gradual deformation parameterization for the fine scale geostatistical model and an upscaling technique for the coarse scale flow simulation model.

The proposed methodology includes:

Perturbation of the fine scale geostatistical model using the gradual deformation parameterization. Gradual deformation ensures the preservation of the overall geostatistical properties of the fine model. Generation of the coarse scale flow simulation model by upscaling the fine scale geostatistical model. Sensitivity computation of the flow simulation results with respect to the fine scale parameterization. This sensitivity computation is analytical and takes into account the upscaling process. Direct updating of the fine scale geostatistical model using classical optimization process. Direct updating ensures consistency between the fine and coarse scale models.

The accuracy of the proposed methodology was improved by calibrating the flow simulation model. The objective of this calibration is to reduce the error introduced by the upscaling step during the flow simulation.

We applied successfully our methodology for fine scale reservoir description by integrating permanent down-hole gauge measurements directly into a three-dimensional geostatistical model containing about two million grid blocks. This test is designed to highlight several key issues of the proposed methodology:

Efficiency of the upscaling step coupled with gradient-based optimization to speed up the history matching process. Usefulness of the calibration step for a correct integration of upscaling techniques in history matching. Capability of the methodology for maintaining consistency and coherency between fine scale and coarse scale models. Improvement of the reservoir characterization by integrating dynamic data at the fine geostatistical scale.

We conclude that the proposed methodology can be used effectively and efficiently for reservoir characterization purposes.
Constraining Reservoir Facies Models to Dynamic Data - Impact of Spatial Distribution Uncertainty on Production Forecasts
Authors: Zabalza-Mezghani I. , Mezghani M. , Blanc G.
Published: December 2007

This paper presents a new approach to constrain reservoir facies models to dynamic data. This approach is mainly based on the combination of an optimization method called the simplex method and parameterization techniques such as the gradual deformation method.

This parameterization technique is well known for its efficiency in constraining geostatistical models to dynamic data. Originaly developped for continuous Gaussian models, the gradual deformation method was extended to facies models [12] and more recently to any kind of geostatistical model. However, the numerical behavior of the inversion can be strongly affected by discontinuities in the model changes in case of facies-based models. Our approach proposes a robust inversion method coupled with the gradual deformation method for the calibration of facies models.

The methodology we present is directly inspired by the construction of a reservoir facies model. We start by generating a related Gaussian continuous geostatistical model. In a second phase this continuous model is transformed according to the number of facies and their proportions to obtain a consistent facies model. Since a direct parameterization of the facies model does not allow the preservation of the geological properties of the model, we perform the parameterization on the related continuous model and then we proceed to the model truncation. In this manner, we can optimize the deformation parameters involved in the parameterization using the simplex method to obtain an history match.

The efficiency of this approach is illustrated by matching an interference test. The parameterization phase was performed using the gradual deformation method. Constrained facies models were thus obtained.

A second phase of this study was devoted to quantifying the impact of uncertainty of spatial facies distribution on production forecasts. In an integrated process, we combine the simplex approach with experimental design theory and the joint modeling technique to achieve a probabilistic production forecast which takes into account the uncertainty on spatial facies distribution and classical reservoir parameters while preserving the history match. This application demonstrates the importance of the interference test matching in reducing the uncertainties on production forecasts.
Adding Value to Impedance Models through Sequence Stratigraphy
Authors: Marzuki Z. , Sams M. S. , Atkins D.
Published: December 2007

Impedance models should be more than just the inversion of seismic data, they should result from the integration of data from diverse sources. This integration adds value to the impedance model by increasing the information content and interpretability of the various data. The integration of geological, geophysical and other data measured in the different domains of time and depth is often not straightforward. One solution is to integrate the data within a common sequence stratigraphic framework.

A case study from a maturing oil field shows how this approach can lead to the improved understanding of the distribution of fluids and reservoir properties. An initial sequence stratigraphic framework was derived from the best quality well log data and preliminary seismic inversion results. This framework was used to guide the conditioning and integration of the all the well log data. As more well log data were integrated, improvements in wavelet estimation and seismic inversion were achieved. The initial framework was refined as the data demanded. The final result was an impedance model in time and depth consistent with the seismic data, the well log data and the geological interpretation.

The development of the most productive interval in the field had previously been based on the assumption that vertical connectivity existed between the different sands within it. Although recent drilling has disproved this assumption and indicated vertical barriers to fluid flow, these could not be imaged using conventional analysis of reflection seismic data. Using the sequence stratigraphic framework to extract impedance values, the separate sand layers could be imaged. These extractions also confirmed that hydrocarbons in an unperforated sand had not yet been depleted and allowed new development drilling locations to be selected.
Subsea Mudlift Drilling: Planning and Preparation for the First Subsea Field Test of a Full-Scale Dual Gradient Drilling System at Green Canyon 136, Gulf of Mexico
Authors: Schumacher J. P. , Dowell J. D. , Ribbeck L. R. , Eggemeyer J. C.
Published: December 2007

Currently the deepwater drilling industry uses single gradient drilling: one single mud weight from the surface to total depth (TD) to control the thin margins between fracture gradient and pore pressure gradient. In this conventional system, a single mud column extends from the rig floor to TD, resulting in a hydrostatic bottomhole pressure. Pore, fracture and mud pressure gradients are referenced to the rig floor.

Dual Gradient Drilling (DGD) provides the same bottomhole pressure with a combination of two fluid gradients: slightly heavier mud from the mudline to TD, and seawater from the mudline back up to the rig floor. All gradients are referenced to the mudline rather than the rig floor. With DGD, the margins between fracture gradient and pore pressure are significantly greater while drilling the well.

The benefits of a dual density system are well documented, but in general, lower cost wells can be drilled more safely and with more completion flexibility than with single gradient systems. Since 1996, the SubSea MudLift Drilling (SMD) Joint Industry Project (JIP) has been developing a dual gradient drilling system and all the associated drilling and well control techniques and procedures.

This paper is the second in a series of papers presented on SMD technology (see SPE 71357 and SPE 71359). It describes the planning and preparation for the world's first dual gradient well. The well will be a partnership collaboration between Texaco, Diamond Offshore and the SMD JIP. It is a Gulf of Mexico Green Canyon well test in a water depth of 910-ft (Figure 1). This location has an intermediate water depth with a known pore pressure environment. It provides an excellent opportunity for extensive testing prior to the final development and delivery of a dual gradient drilling system for use in ultra-deepwater (beyond 6000 ft).
Large-Scale Evaluation of Alloy-Metal Annular Plugs for Effective Remediation of Casing Annular Gas Flow
Authors: Carpenter Robert B. , Gonzales Manny , Griffith James E.
Published: December 2007

Annular gas pressure, also known as sustained casing pressure (SCP), is a common problem and potential threat to the safety of personnel and equipment, as well as to the environment. Improved means of primary cementation and life-of-the-well simulations show promise for preventing future annular gas-flow problems. However, there has been little success in eliminating SCP, once developed, without jeopardizing the economic life of a well.

Possible solutions to SCP in the form of remediation include bullheading cement, injection of zinc bromide brines into the well's annulus, or use of expensive resins to seal the annulus. A proposed solution that can compensate for the drawbacks of the above options and has shown promise on small-scale physical models is palletized alloy-metal. This solution involves placing palletized alloy-metal into the well's annulus, heating the alloy-metal above its melting point, and then allowing the alloy-metal to cool. These steps form a continuous alloy-metal plug in the well's annulus.

Data and conclusions documented in this paper are from full-scale pipe-in-pipe and pipe-in-sandstone geometry models having the following scope:

Geometry of 5 ½ × 8 ½-in. pipe-in-sandstone and 10 ¾ × 13 ⅜-in. pipe-in-pipe configurations Model length limited to 15 ft and deviated at 30° from vertical Alloy-metal pellets placed and activated with water-based drilling fluid present in annuli Temperature limited to 200°F

Results are also documented by dissecting the models and photographing the exposed cross-sections. Information gathered in this testing will help with the field introduction of this technology.
New Treatments Substantially Increase LOT/FIT Pressures to Solve Deep HTHP Drilling Challenges
Authors: Webb Sid , Anderson Tom , Sweatman Ron , Vargo Richard
Published: December 2007

Insufficient borehole pressure integrity (BHPI) is a major drilling challenge in deep, high-temperature, high-pressure (HTHP) wells in California and other areas. Shale and sandstone formations with low BHPI may be weakened by leaking faults/ fractures or poor rock properties, causing lost returns with mud weights close to pore pressures. Drilling through depleted or low pore pressure formations with some probability of drilling into higher pressured zones in the same hole section compounds the severity of this challenge in the Temblor formation in Kern County, California.

This challenge was solved by an innovative treatment applied in the Berkley East Lost Hills No. 1 well. Compared to conventional methods, it increased leakoff test (LOT) and formation-integrity test (FIT) pressures to incremental values higher than those typically seen in the industry. Increasing BHPI allowed an additional 960 ft to be drilled before a 7-in. liner was set, and the well was drilled to 19,724 ft. This depth met the objective of the well (to obtain full penetration through the objective sands) and allowed the subsequent discovery of a pay zone. If the new treatment to increase the LOT had not been used, the 7-in. liner would have been set early, and it is unlikely that the discovery zone would have been penetrated.

Preventing skin and formation damage in potential zones of interest while treating weak points was another major concern heightened by a wide range of pore pressures. This paper discusses a theoretical mechanism to help explain how the treatment rapidly and substantially increases pressure integrity across both sand and shale formations. Minor penetrations in high and low-permeability sandstone-core tests help explain why the treatment system minimizes or prevents skin damage. Skin damage in the zones of interest may be prevented or minimized by BHPI treatments that only enter leaking fractures or faults.

Further development and deployment of BHPI treatment technology promises a step-change in industry practice to optimize well plans with lower cost programs for drilling fluids, casing design, cementing, and completion equipment. Optimized well designs should reduce both drilling days and flat time by allowing operators to drill smaller-diameter holes while using fewer casing strings to achieve the same production-string dimensions.
An Analytical Solution to Estimate the Optimum Number of Development Wells to Achieve Maximum Economical Return
Authors: Corrie R. D.
Published: December 2007

The preliminary estimate of the number of wells required to exploit a reservoir is one of the most important variables needed to decide on an oil field development. Traditionally, the optimum number of wells has been determined graphically from a plot of economic return verses well spacing. This paper derives an equation to solve this problem directly without the plot and presents an illustrative example for its application. The independent variables of the equation are the reserves, the initial production rate per well (assumed to decline over life), the oil price at wellhead, the total present value cost per well and the interest rate.
Optimisation of Emissions Through the Application of a Mobile Variable Tip Flare System
Authors: Manning Julian
Published: December 2007

Increasing legislative requirements on a global basis are driving the development of innovative solutions to reduce emissions. Flaring and venting of waste hydrocarbon gases is a known contributor to pollution and increasing pressure is being exerted onto operators to monitor and minimise emission levels.

BJ Process and Pipeline Services operate a "Hi-Lo" variable tip flare system which has proven to achieve outstanding emission results during a number of separate operations, including the incineration of Butadiene / Styrene waste gas during a plant shutdown and flaring high Hydrogen Sulphide concentration gas during a production well test. The system has many applications to allow the safe flaring or incineration of waste gases where stringent emission results need to be constantly demonstrated.

The fully portable system is automated using a comprehensive Programmable Logic Controller (PLC) package to constantly monitor and control gas flow, percentage of air mixture, auxiliary fuel gas concentration and the positioning of the variable tips to maintain constant tip velocity.

The paper discusses the systems effectiveness, design, applications and an analysis of the emission results achieved in comparison to legislation.
Imaging through Crude Oil with High Resolution, Optically
Authors: John A. Hother
Published: December 2007

We have combined our expertise in space-imaging technologies and our knowledge of oilfield industry needs to create an imaging technology that can produce high-resolution optical images through crude oil.

The first application we have explored is a new form of downhole video that requires no preparation of the well (ie no flushing), saving time and cost in interventions. The new technology opens-up many further instrumentation possibilities for the oil industry.

The results of the feasibility study demonstrate the high quality images that can be achieved through crude oil.

Now we are developing a trials prototype in a Joint Industry Project, sponsored by Amerada Hess, BP, Chevron and Shell.
Modeling and Mitigation of Severe Riser Slugging: A Case Study
Authors: Meng Weihong , Zhang Jeff J.
Published: December 2007

In offshore oilfield development projects using subsea tiebacks, severe riser slugging is of great concern, particularly for flowlines with downward slope at the riser base. In a recent conceptual design for a deepwater field, the flowline system consisted of a downward pipeline about 2,100m long and a steel catenary riser in 700-m deep water. Transient flow analysis indicated that severe riser slugging would occur. The paper describes the analysis of several mitigation techniques - increasing well lift-gas injection rate, injecting lift-gas at riser base and reducing riser diameter.

The study revealed that these severe slug mitigation techniques reduced the slug volume and frequency with different efficiencies. For the particular case study, increasing the lift gas at wellbore bottom of 1 MMSCFD from the base case of 3 MMSCFD was the most efficient technique to eliminate severe slugging. Riser base gas lift required 3 MMSCFD in addition to the 3 MMSCFD lift gas at the bottom of wellbore. Mitigation by reducing riser diameter was not effective because it required a 2" reduction in the diameter and would make flowline pigging difficult. The analysis also showed that including the wellbore in transient flow models for the short-distance flowlines is essential. Without the wellbore model, no severe riser slugging was predicted.
Integrated History-Matching of Production and 4D Seismic Data
Authors: Gosselin Olivier , van den Berg Stanislas , Cominelli Alberto
Published: December 2007

The reservoir characterisation methods are still improving the integration of all available data for more accurate predictions, but the history-matching confrontation between observed and simulated data as predicted by the model remains the crucial test. Time-lapse 3D seismic data now provides a new type of information on the dynamics of fluids in the reservoir, relating variations of seismic signal to movement and/or depressurisation of hydrocarbons. This powerful reservoir-monitoring tool can be fully exploited when it is used to update the reservoir model in an integrated matching loop of all history data – 4D data, spatially distributed over the whole reservoir, jointly with time series of well observations. In a classical gradient-based minimisation of an objective function, measuring the mismatch between observed and simulated data, we add a seismic term to the well term. This contribution, defined in terms of elastic parameter variations within the reservoir, comes from an inversion of the seismic signals. On the other hand the fluid flow simulator is coupled with a petro-elastic module to convert the simulated saturation/pressure and static rock properties into simulated elastic properties. The optimiser uses gradients of both terms to minimise the global mismatch, updating the reservoir properties. In this paper, we justify our approach using elastic parameters, describe the relationships to derive elastic properties from reservoir properties, and present the integrated iterative loop matching both kinds of dynamic data (production and 4D seismic), based on sensitivity analysis to select the most efficient parameters and applied to the synthetic PunqS3 case6,1.
The Development of a Major Gas-Condensate Field
Authors: Saadawi Hisham
Published: December 2007

A major grass-root gas project has been recently implemented to develop two condensate reservoirs in a field onshore Abu Dhabi. The project facilities comprise of a gas gathering system, a processing plant for condensate recovery and an injection system to recycle the lean gas back to the reservoir.

This paper addresses the basic design concepts and describes the surface facilities. The paper also outlines the project implementation strategy as well as the commissioning and start up experience.
Geological Sequestration of CO2 in Deep, Unmineable Coalbeds: An Integrated Research and Commerical-Scale Field Demonstration Project
Authors: Reeves Scott R.
Published: December 2007

Coalseams represent an attractive opportunity for near-term sequestration of large volumes of anthropogenic CO2 at low net costs. There are several reasons for this: Coals have the ability to physically adsorb large volumes of CO2 in a highly concentrated state.Coals are frequently located near large point sources of CO2 emissions, specifically power generation plants.The injection of CO2 into coalseams actually enhances the commercial methane recovery process.The recovery of coalbed methane is enhanced when the injected gas contains nitrogen, a major constituent of power plant flue gas.

A joint U.S. Department of Energy and industry project to study the reservoir mechanisms and field performance of CO2 sequestration in coalseams has recently been initiated. The project involves laboratory and field-testing to define critical reservoir mechanisms, including multi-component (CO2-CH4-N2 ternary) sorption behavior. Two existing fields in the San Juan Basin, the most prolific coalbed methane basin in the world, are currently under CO2 and/or N2 injection. These two fields, the Tiffany Unit (operated by BP) – now under N2 injection (but with mixed CO2/N2 injection being studied), and the Allison Unit (operated by Burlington Resources) – under CO2 injection since 1995 will be thoroughly studied via reservoir simulation to understand CO2 sequestration and enhanced coalbed methane recovery performance, using both pure CO2 and N2, as well as CO2/N2 mixtures. This paper presents the fundamental reservoir mechanisms of CO2 sequestration and enhanced recovery of methane from coalseams, and the field performances to date of the Tiffany and Allison Units.
Responsible Environmental Management Leads to Improved Resource Recovery - The Laminaria / Corallina Gas Re-Injection Project
Authors: Ryan S. A. , Twartz S. K. , Gordon D. M.
Published: December 2007

This paper presents a study of a gas re-injection project, designed with the dual objectives of emissions reduction and enhanced oil recovery in an Australian offshore oil field. A significant reduction in greenhouse gas emissions has been achieved since the project commenced late in 1999, with some 1.3 million tonnes of CO2 emissions avoided in year 2000 alone. Miscible displacement is expected to add around 6 million barrels to ultimate recovery from the Corallina reservoir, and use of stored gas as fuel is expected to achieve significant reductions in operational expenditure later in field life.

Gas injection for the purposes of enhancing oil recovery has been common oilfield practice for several decades. Many technical papers have been written on this subject, from both theoretical and practical points of view. Projects that focus exclusively on greenhouse gas control (either by sequestration or emission reduction) are less common, although the level of research is rapidly increasing as environmental awareness spreads throughout the industry. The Laminaria / Corallina gas re-injection project is designed to achieve both objectives.
Reservoir Monitoring Methodology for a Giant Gas Field
Authors: Potapieff Igor , de Wit Joop
Published: December 2007

The Tunu field is the major gas supplier of the East Kalimantan system (Indonesia). Production commenced in 1990 and more than 200 wells have been drilled to date. The field exported an average 1.3 Bcf/d in 2000.

In 1999, an extensive reservoir-monitoring program was launched: successful implementation of Multi-Rate Production Logging (MRPL), creation of reporting templates for MRPL and Pressure Build Up (PBU).

This well-defined standardised process has resulted in a significant enhancement of the reservoir description and understanding of the production performance with extensive use of classical reservoir monitoring tools. Well operations have also been streamlined and optimised.

So far, approximately 150 PBU and 40 MRPL have been fully processed, with presently 5 MRPL's acquired per month.
Microbial EOR Study to Improve Sweep Efficiency In Caltex Fields. Phase I - Nutrient Selection
Authors: Kadarwati Sri , Udiharto M. , Hs Noegroho Hadi , Brinkman Joseph P. , Yulianto Bangun
Published: December 2007

The objective of this research is to find a cost effective nutrient that will stimulate the growth of in-situ microbes in Caltex Pacific Indonesia (CPI) oil fields to create sufficient biological products to plug high-permeability reservoir thief zones. If successful, injection fluids may be diverted into unswept regions of the reservoir, increasing the sweep efficiency and extending the production life of watered-out oil fields. This paper describes how a wide range of nutrients were researched and tested in the laboratory to achieve the objective. The primary findings of this study show that several nutrients were successful at creating bioproducts at high temperature, low salinity, reservoir conditions, and that molasses may be the most cost effective nutrient for all three CPI waterflooded reservoirs tested: Balam South, Bangko, and Minas fields. As a result of this work, laboratory studies were started to see to if the microbial growth created in laboratory test tubes can be recreated within reservoir core plugs to achieve sufficient permeability reduction to justify field trial(s). The core flood process and techniques will be presented in a separate paper.
Openhole Expandable Sand Screen Completions in Brunei
Authors: Lau Hon Chung , Van Vliet Jacques , Ward Mike , Morin David , Djamil Arifun , Kuhnert Paul , Aldaz Walter , Shanks Steven
Published: December 2007

Expandable Sand Screen (ESS®) was deployed successfully as a sand control device in two horizontal openhole completions in two geologically different offshore fields in Brunei. A critical success factor was the choice of a drill-in-fluid (DIF) that maintained hole stability and gave a near-gauge hole during running and expansion of the ESS. Field experience and extensive research led to the choice of a synthetic-based DIF for one well but a water-based DIF for the other well. Challenges unique to the deployment of ESS in these wells are discussed.