bluuebunny/crossref_metadata_2025 huggingface dataset:
Tube Pickling Procedures: Case Studies
Authors: Al-Mutairi S. H. , Nasr-El-Din H. A.
Published: December 2007

Tubing pickle treatments can eliminate formation damage that is caused by introducing millscale, pipe dope and other tubular contaminants into the formation. Two of acid pumping techniques implemented to perform the pickling treatments are bullheading and coiled tubing. In the bullheading method, the acid is pumped down the tubing, then the spent acid is lifted to the surface using reservoir pressure. Coiled tubing is another method where the acid is pumped down the coiled tubing, and flowed up through the tubing/coiled tubing annulus.

This paper examines the advantages and disadvantages of the two commonly used techniques for tubing pickling: bullheading and coiled tubing. The efficiency of each method is analyzed based on extensive analysis of field samples. In addition, the paper also addresses the effects of acid volume, concentration, and pumping flowrate on the efficiency of removing mill scale from the wellbore.

Field data indicated that tubing pickle is a must. Extremely high levels of total iron (up to 105,000 mg/l) were noted in the spent acid. The relationship between dissolved iron and acid concentration profile depended on the mode of acid pumping. In the case of bullheading, the iron peak coincides with the tail of the acid peak, whereas it coincided with the leading edge in the case of coiled tubing.
Getting a Clear Picture - Individual Zone Testing of the Khuff Reservoir Through First Application of a Zonal Isolation Completion and Nondamaging Drilling and Completion Fluids
Authors: Sorgard E. , Knox D. , Svoboda C. , Mason S. , McNeil B.
Published: December 2007

The North Field is a major gas field in the Khuff formation, offshore Qatar. Traditionally, this reservoir has been drilled with reduced solids drilling fluids and completed by heavily acidising the payzone in order to maximize production.

The purpose of appraisal well NFS 1-1 was to obtain high-quality representative formation fluid samples from each of the identified producing zones in the Khuff. The detailed gas analysis was required to determine the specifications of the Gas-To-Liquid (GTL) Plant to be constructed to process production from the field.

In order to achieve this, a new testing technique was developed using a ported liner, a high density, low solids reservoir drilling fluid, and a combination enzyme/chelating agent breaker to remove the filter cake prior to testing the individual zones. In order to ensure the success of this challenging operation, a high degree of collaboration between the operator and the supplier of drilling, completion and stimulation fluids was imperative.

The design and engineering of the fluids used during coring, logging, completion and well testing of NFS 1-1 is examined in this paper.
Characterization of the Invasion Profile and its Components Due to Drilling Fluid Mudcake Filtration, Using the Synchrotron Light X-Ray Fluorescence
Authors: Neto J. C. Q. , Ribeiro J. L. B. , Lopes R. T. , Anjos M. J. , Bianco L. C. B. , Coelho M. V.
Published: December 2007

During well drilling operations, the invasion of the porous media around the wellbore by a certain quantity of drilling fluid components is likely to happen to build a stable mudcake. For a horizontal open hole well, the mud cake is kept during drilling and completion operations giving stability to the borehole. Because the drilling fluid is heavier than the formation fluids, solid particles and fluid components are pushed into the formation establishing a filtration process. At some point, the mud cake must be removed and a clean up procedure is done. For production wells, the majority of the mud cake and invaded components are removed with the well production and the resulting skins are usually acceptable without any secondary treatment. However, for injection wells, such removal is always a problem and special treatments are needed. The success of such treatments is based on the knowledge of the invasion profile and their composition. Therefore, a better characterization of the invasion profile could improve substantially the clean up procedures and the treatment selection.

In this first result the aim of study is to address this problem an experimental procedure was developed to identify and characterize the profile of drilling fluid invasion. This technique used the X-Ray Fluorescence Beam line (XRF) from the Synchrotron Light at the Brazilian Synchrotron Light National Laboratory (LNLS) in Campinas, São Paulo State, Brazil figure 1. This methodology allowed the determination of the invasion profile in synthetic unconsolidated sandstones similar in composition to the reservoir rocks.

Along with the invasion profile, μ-SRXRF analysis was used to map and identify drilling fluid components that may have invaded the core. The identification of these components provided information to differentiate and identify carbonates and polymers in terms of concentration and penetration.
Dynamic Mud-Cake Removal Evaluation Under Annulus Hydrodynamic Conditions
Authors: Robles J. , Criado M. A. , Jensen E. , Morris W.
Published: December 2007

In the last decade drilling fluids have undergone a continuous evolution towards the challenges of new drilling technologies. This process forced cementing companies to improve the mud-cake cleaning systems efficiency in order to achieve successful cementing jobs.

A basic procedure to evaluate drilling fluids compatibility with spacers, preflushes and cement slurries is provided in API recommended practice 10 B. However, no quantitative methods to evaluate preflushes mud removal efficiency are proposed. On the other hand, several laboratory methods have been developed to analyze this issue, although most of them are based on experiments performed at unrealistic down-hole conditions.

This paper presents a new laboratory method to dynamically evaluate preflushes performance. The drilling fluid is circulated through a cell at a similar hydrodynamic flow regime expected in the well annulus. The mud cake is generated on four different filtering materials, applying differential pressure at the bottom hole circulating temperature.

The mud and filter-cake removal is evaluated by two different techniques, static gravimetric and dynamic impedance. This last technique provides a continuous indication of the cake thickness variation during the test. Therefore, the preflushes chemical, viscous and abrasive action can be evaluated while the test is conducted.

Three case studies, a low solids KCl, a PHPA and a plain water base drilling fluid, are reported were the performance of different preflushes systems are evaluated. The results of these studies were used to modify the preflushes pumping sequence and to adjust their volumes based on the information obtained from the impedance trends. The cleaning efficiency of viscous spacers used in-between chemical washes and the effect of mud filter cake leek off are discussed.
Sulfate Removal for Barium Sulfate Scale Mitigation -- Kinetic vs. Thermodynamic Controls in Mildly Oversaturated Conditions
Authors: Simpson C. M. , Graham G. M. , Collins I. R. , McElhiney J. , Davis R.
Published: December 2007

Conventionally, scale mitigation is achieved using chemical inhibitors either by squeeze treatment into the reservoir or continuous injection. However, with new fields encountering increasingly more challenging environments, or when the economic impact of chemical intervention by squeeze treatment is large (e.g. subsea fields with poor bullhead chemical placement), other methods of scale control such as the use of low sulphate sea water (LSSW), must be considered during the front end engineering and design (FEED) stage of a field development. Nevertheless, for conventional sulphate reduction packages (SRP's) that reduce the sulphate concentration in the injected sea water typically towards 40 – 50 ppm, there remains a residual scaling risk and the requirement for periodic squeeze treatments.

Previous work reported at the 2004 SPE Oilfield Scale symposium (SPE 87465) examined the level of sulphate reduction required to mitigate the requirement for even periodic squeeze treatments against barium sulphate scale. This showed that sulphate levels of 20 ppm were required in order to prevent scale formation under down hole production conditions, although it was also demonstrated that thermodynamically the system remained oversaturated with barium sulphate.

This paper expands considerably on this preliminary "field specific" case and examines the impact of LSSW on the scaling kinetics across a broad range of formation water compositions (barium ranging from 150 ppm to 650 ppm) and at temperatures between 80°C and 120°C. The paper therefore investigates the relationship between scaling kinetics and thermodynamics in relatively mild scaling environments and illustrates that whereas extremely low levels of sulphate would be required to completely prevent scale from a thermodynamic viewpoint, the kinetics of scale formation may prevent scale precipitation under down hole production conditions, with additional continuous injection inhibitor applied at wellheads to protect flow lines etc. In summary, this paper presents results from an extensive series of long term dynamic flow and pseudo static performance tests designed to determine the relative impact of thermodynamics and kinetics on the residual barium sulphate scaling risks associated with the injection of LSSW for pressure support.
Wireline Replacement in Pilot Wells by LWD Tools Including Formation Testers
Authors: Tigre C. , Rafainer G.
Published: December 2007

The use of an eight-inch diameter formation-tester-while-drilling tool for 12 ¼ in to 16-in. holes has provided the option to significantly if not totally replace wireline logging operations in pilot sections of planned horizontal wells in Brazil. When using LWD tools only, sections of a pilot interval do not need to be plugged and abandoned, as had been the practice. The option with a complete suite of LWD tools can greatly reduce operational risks and save time and money. Savings of up to six rig days and US$ 900.000,00 can be expected.

In the past, a 12 ¼ in pilot section was drilled before the horizontal section of a planned horizontal well was developed. The purposes of the pilot section were to confirm top and base of target reservoir and evaluate its production characteristics. While drilling pilot sections, the LWD tools were limited to gamma, resistivity and pressure while drilling. Thereafter, a more comprehensive wireline logging suite was run including, wireline-run formation testers. To avoid the need for a costly pipe-conveyed logging runs, these sections were also limited to inclinations less that 50 degrees. After the logging runs, the pilot sections were typically plugged and abandoned with a sidetrack section drilled off the top of the last cement plug.

The availability today of LWD formation tester allows for a new and less costly option. The 12 ¼ in. section of the planned well takes an S-shape profile, getting close to the target reservoir at inclination higher than called for in running wireline, dropping off to reach the base of the reservoir and continuing to its final TD destination. It is not necessary to plug and abandon all the pilot section, and the planned drilling, including logging, can be completed more quickly and efficiently.
Improving Water Saturation Prediction with 4D Seismic
Authors: Wu J. , Mukerji T. , Journel A. G.
Published: December 2007

Seismic data provides a unique source of information widely used for reservoir characterization. High resolution 3D seismic impedance field is critical for building a model of facies distribution. 4D seismic time-lapse can reflect the water saturation difference (time-lapse), hence could point towards potential facies (dis)continuities not originally apparent from the static data.

An interactive procedure is proposed to improve the prior facies model by spotting areas of large discrepancies between the recorded 4D seismic data and the corresponding forward simulated time-lapse data. Various indicators of discrepancy are proposed. The subsequent correction honors the prior geological scenario. It is fast because it does not call for any iterative optimization.
Resolving the Nightmare of Performance Reporting and Portfolio Management - A Web Based Approach
Authors: Nickle B. , Strickland R. , Purvis D.
Published: December 2007

Many papers have been written concerning the energy industry's need to become more efficient in its methodologies and operations. The shrinking qualified workforce and global economic factors are placing further pressures on the energy sector to streamline processes. This requirement extends itself to all phases of the energy industry, especially with multidisciplinary multi-organizational teams.1-5

For the past 5 years a major private equity player has successfully exploited the digital oil field to streamline its asset management processes. This company manages its 2.3 billion dollar oil and gas portfolio with a staff of 5 professionals by utilizing a web-based portfolio management tool. This same staff of 5 annually approves over $100 million in AFE's.

Since inception this web-based application has been successfully deployed to manage 36 different partnerships across the United States. This system has benefited by the proactive input of over 300 industry professionals throughout the application development and deployment cycles. The software currently consists of over 60 different analytical tools to analyze the performance of a portfolio.

This paper examines the use of web based technologies to build a portfolio management system. There are many pitfalls and challenges to overcome to ensure the success of an application designed to monitor performance and measure value. From specifications through rollout to E & P companies aspects of design and deployment are thoroughly explored.
Permeability Estimation Using a Hybrid Genetic Programming and Fuzzy/Neural Inference Approach
Authors: Xie D. , Wilkinson D. , Yu T.
Published: December 2007

We have developed a methodology that provides permeability estimates for all rock-types or lithologies, for a wide range of permeability. This is a hybrid Genetic Programming and Fuzzy/Neural Net inference system and which utilizes lithologic and permeability facies as indicators. This work was motivated by a need to have a volumetric estimate of permeability for reservoir modeling purposes. To this end, for our purposes, the inputs to this process are limited to properties that can be estimated from seismic data. The permeability transform is first estimated at the well locations using core permeability, elastic parameter logs and porosity. The output from the process can then be used, in conjunction with estimates of these properties from 3D seismic data, to provide an estimate of permeability on a volume basis. The inputs are then, the volume of shale (Vsh) or any other log type used to determine lithology, the sonic and density logs, the porosity log and core permeability measurments. The transform system is composed of three distinct modules. The first module serves to classify lithology and separates the reservoir interval into user-defined lithology types. The second module, based on Genetic Programming, is designed to predict permeability facies within lithology type. A permeability facies is defined as as a low, medium or high permeability set associated with each lithology type. A Fuzzy/Neural Net inference algorithm makes up the third module of the system, in which a TSK fuzzy logic relationship is formed, for each permeability facies and lithology.

The system has been applied in two oil fields, both offshore West Africa. In comparison with current estimation approaches, this system yields more consistent estimated permeability. The results from conducting cross-validation suggest this methodology is robust in estimating permeability in complex heterogeneous reservoirs. This system is designed to use elastic log properties inverted from seismic data, such as acoustic velocity and density as input so permeability volume can be obtained.
Nonpolymer Surfactant Enhances High-Strength Hydrofluoric Acid Treatments
Authors: Cawiezel K. E. , Devine C. S.
Published: December 2007

Traditionally, operators have been reluctant to use acids with HF concentrations greater than 3% to remove drilling mud and stimulate the near wellbore region due to fear of formation deconsolidation in the near wellbore region. With some formations, even 3% HF concentrations will cause deconsolidation.

During recent laboratory testing, it was discovered that the addition of the surfactant ("TH-1") to several conventional mud acid formulations and to several strengths of Retarded Acid System (RAS) formulations produced good stimulation in sandstone formations.

Results of testing indicate that the use of the surfactant produces acid formulations which exhibit improved penetration of live acid, increase post-test permeability of test samples by a significant amount, and minimize rock disaggregation at the core face.

The concentration of surfactant added is dependent on the unstimulated permeability of the rock, the rock mineralogy, and the temperature of the test. The concentration of surfactant tested to date ranges from 0.25 to 2%.

Acid containing the surfactant may plug off higher permeability zones and streaks in test samples, allowing the acid to react with lower permeability streaks and zones.

This technique is useful for self-diversion of acid treatments in sandstones and for causing a significant increase in permeability in sandstones which cannot be fracture stimulated. Hydrocarbons contacting the fluid during flowback will break the stiffened acid. The system is polymer-free so no polymer damage is present.
Optimization of Synthetic-Based and Oil-Based Mud Displacements with an Emulsion-Based Displacement Spacer System
Authors: Berry S. L.
Published: December 2007

Proposal

Effective removal of drilling muds and related solids from cased wellbores prior to adding solids-free brine during the completion process is a critical point for well operations. Efficient displacement of the drilling fluid itself and any particles attached to the casing wall is essential to maintain completion brine and mud integrity, as well as to reduce filtration costs and rig time. A failed displacement can lead to completion complications (such as stuck packers) or potential formation damage due to loss of drilling mud solids to the formation. Modern drilling fluids have progressed to meet more challenging, drilling applications, as well as stricter health, safety, and environmental standards. Many of these advanced drilling fluid systems contain new emulsifier and additive packages, which have increased the difficulty in removing drilling mud from the cased wellbore with traditional displacement spacer surfactant systems.

This paper discusses a laboratory test used in the mud removal studies with an emulsion-based displacement spacer. It also details the efficiency of an emulsion-based displacement spacer in removing actual field compositions of synthetic (SB) and oil-based (OB) drilling muds. Mud parameters such as density, base-oil type and rheologies are detailed to characterize the type of mud and the difficulty in displacing the mud system from the wellbore casing. Also, the environmental advantages of this low-toxicity, non-polluting emulsion-based displacement system are outlined.

Field case histories detail the use of this emulsion-based spacer in the North Sea to displace a wide range of SB/OB drilling mud systems. This paper also outlines how this product optimized removal of SB/OB drilling mud systems, decreased rig operation time, and reduced the volume of mud solid slop due to efficient phase separation and emulsion breaking of the drilling mud systems.
A Novel Response Surface Methodology Based on "Amplitude Factor" Analysis for Modeling Nonlinear Responses Caused by Both Reservoir and Controllable Factors
Authors: Li B. , Friedmann F.
Published: December 2007

Response surfaces (RS) are proxies to reservoir simulators. They relate responses, such as oil rate to key reservoir (i.e., geological parameters) and/or controllable (i.e., wells parameters) factors in simple analytical forms. These proxies can then be used for uncertainty computation, instead of time consuming simulators.

Validity and Efficiency of RS construction techniques depend on the degree of non-linearity. Traditional design of experiments (DOE) coupled with regression methods generate polynomial-type RS. They work well for mildly non-linear problems. However, the reconstructed RS can become substantially inaccurate, if RS exhibits stiff non-linear features. Substituting interpolation methods for regression often improves a proxy's accuracy. However, they tend to smooth out non-linearity and are costly when the non-linearity is unevenly distributed in the parameters' space. Efficient experimental space partitioning coupled with interpolation can further improve proxies' accuracy1. However, space partitioning results in low computation efficiency.

We introduce a novel response surface methodology (RSM), which accurately and efficiently handles non-linear effects without space partitioning. The basic idea is to model non-linear responses by: Identifying a kernel sub-space of the initial parameters space which contains the factors causing highly nonlinear effects on RS;Extracting the highly non-linear effects from RS by ‘amplitude factor’ analysis;Treating all other effects by ‘phase factor’ analysis;Modeling all effects on the response with ‘thin plate’ spline interpolants.

We then test this method to generate RS of arbitrary shapes using a synthetic model and a real reservoir model. We generate RS for oil rate and water cut as functions of key parameters. We validate this method's accuracy for the reconstructed RS and the data collection efficiency. We also compare it with traditional RSM. We show that this novel methodology outperforms other standard RSM when nonlinear effects on RS are very strong in the parameter space.
Managing Drilling Performance: Technical Analysis, Well Challenges, and Field Engagement
Authors: Iyoho W. , Adeleye A. , Virginillo B , Hovland K
Published: December 2007

Within a climate of increasing oil and gas prices, drilling has been caught in a cycle of new, more expensive technology and increasing service and commodity prices. In order to maintain cost effective drilling excellence, Anadarko Canada Corporation's drilling department has developed a multifaceted approach with three major components; pre and postdrill analysis, collaboration and technology. While these three components are commonly part of any current drilling operation, the rigorous approach ACC has applied continues to generate uncommon results in both in-fill and more technically challenging, poorly delineated drilling fields in Western Canada.

Our approach and the results generated in two distinct areas of operation are outlined here.
Getting Full Value from Reserves Audits
Authors: Etherington J. R.
Published: December 2007

Most oil and gas companies retain consulting firms to conduct "independent audits" of a portion of their annual reserves disclosures. Processes are loosely based on financial audits, but there can be significant differences.

Reserves are estimated marketable quantities and values of oil and gas resulting from a defined development plan. The process that examines the standards, controls and procedures applied to prepare these estimates can take several forms: 1) a "reserves evaluation" is a full independent study using raw data, 2) a "reserves audit" employs sufficient tests of the client's evaluations to provide an opinion that results are free from material misrepresentations, 3) in a "reserves review", the auditor assesses the "plausibility" of results based principally on staff interviews, and 4) a "reserves process audit" critically examines the overall procedures and controls applied by the company.

Regulatory disclosures are usually confined to a subset of the total resource assessments used for internal project planning. For example, the Security and Exchange Commission (SEC) guidelines restrict disclosures to Proved reserves and this may be the only estimate provided by audit firms. It is recommended to specify a full reserves and resource audit using a combination of Society of Petroleum Engineers (SPE) and SEC guidelines. Results can then be used to validate a single assessment that supports both disclosures and internal planning.

Many authors contend that full evaluations by an external consulting firm should form the basis of all reserves disclosures. Critical analysis of alternative reserve assessment work flows challenges this approach. The preferred model places third party evaluations in the context of a total quality assurance and control process managed by an internal but independent, corporate Resource Management group.

The project team responsible for a property's development is best positioned to forecast production (reserves) and cash flow (value) scenarios. However, to protect against internal bias, a second, independent opinion may be sought. Given the major uncertainties involved, it is not unusual to obtain significantly different interpretations. Assessments can be improved by engaging the teams in a discussion of their assumptions and interpretations. This process model gets full value from reserves audits
The Influence of Interfacial Tension on Water/Oil Two-Phase Relative Permeability
Authors: Shen P. , Zhu B. , Li X. -B. , Wu Y. -S.
Published: December 2007

Water-oil relative permeability characterizes two-phase flow and displacement processes, and its functional form is difficult to determine in a particular reservoir study. Adding various chemical agents into the displacing aqueous phase during alkaline-surfactant-polymer combination chemical flooding in oil production significantly changes interfacial tension (o) on water-oil interfaces, and also increases the degree of difficulty in measuring such changes in the laboratory or field. To overcome the limitations of the existing laboratory measurements of relative permeability (which are applicable only for high ranges of interfacial tension [e.g., σ > 10-2 mN/m], we present a comprehensive experimental study of two-phase relative-permeability functions in much lower, more realistic interfacial tension water-oil systems. In particular, we have (1) develop an improved steady-state method of measuring water-oil relative permeability curves; (2) proven that a critical interfacial tension value (σc) exists such that interfacial tension has little impact on relative permeability for σ > σc, while if σ < σc, relative permeabilities to both water and oil phases will increase with decreasing interfacial tension; and (3) shown that a logarithmic relationship exists between water-oil two-phase relative permeability and interfacial tensions. The experimental results reported here and conceptual models proposed here will be useful for feasibility studies, optimal designs, and numerical simulations of different chemical flooding operations in oil reservoirs.
Effective Torque Management of Wytch Farm Extended-Reach Sidetrack Wells
Authors: Robertson N. , Hancock S. , Mota L.
Published: December 2007

Wytch Farm was at the forefront of extended-reach drilling (ERD) during the 1990's. This was achieved through opportunity, innovation, technology and team work. Late life management of the field has now required that cost-effective sidetrack wells be drilled to sweep the remaining oil in place in the offshore part of the field.

As with many ERD developments, one specific challenge associated with the original Wytch Farm wells was the ability to control torque and drag within manageable levels. While drilling the original ERD wells, it was noticed, by chance, that the addition of particular loss circulation material (LCM) had a profound impact on torque and drag. The mechanism by which this was happening was not fully understood at the time, but considered to be a combination of hole cleaning improvements and mechanical friction reduction.

In an attempt to quantify and better understand the friction reducing mechanism, a series of controlled field experiments have been undertaken.

This paper describes the basis for the field experiments, implementation plan, analysis techniques and results. Results correlate the amount of LCM addition with a marked reduction in friction factor. The effectiveness of LCM sweeps for torque and drag reduction is also discussed. Understanding the relationship between LCM addition and torque and drag reduction will offer cost savings during the drilling of more demanding ERD wells. Explanations of the torque and drag reduction mechanism are also discussed in the paper.
Experimental and Stochastic Modeling of Diffusion-Controlled Matrix-Fracture Transfer in Naturally Fractured Reservoirs
Authors: Hatiboglu C. U. , Babadagli T.
Published: December 2007

Co-and counter-current type transfers due to diffusion between matrix and fracture were studied experimentally using 2-D glass-bead models. Mineral oil and kerosene were used as the displaced phase. The model saturated with oil was exposed to pentane diffusion under static conditions (no flow in fracture) to mimic matrix-fracture interaction during gas or liquid solvent injection in naturally fractured reservoirs. Displacement fronts and patterns were analyzed and quantified using fractal techniques to obtain correlations between the fractal properties and displacement type. Displacements resulted in a mixture of diffusion limited aggregation (DLA) and invasion percolation (IP) type patterns mainly depending on the interaction type (co-or counter current), oil type and displacement direction (horizontal and vertical). Conditions yielding different types of displacement patterns were identified.

Finally, a stochastic model simulating the diffusion process was developed using combined and modified IP and DLA algorithms. The experimental observations were matched to the displacement patterns obtained through the stochastic modeling.
High Angle HPHT Wells
Authors: Gjønnes M. , Myhre I. G.
Published: December 2007

The Kristin field is the most extreme HPHT field in Norway with a reservoir pressure of 911 bar and a temperature of 175°C. This gives an equivalent pore pressure of 1.96 sg. With additional safety margin, trip margin and riser margin, it requires mud weight up to 2.07 sg to balance the pore pressure. Combining very high mud weight, high temperature, sub sea operation, gas reservoir and high inclination create a formidable challenge to tools, equipment, procedures and personnel. In October 2004 Kristin finished drilling the first high angle sub sea gas producer in the world under such HPHT conditions. The positive pressure test of the 7" liner marked the successful completion of the drilling phase. The achievement on Kristin introduces a new term in to the oil and gas industry. HAHPHT wells, high angle high pressure high temperature wells. The well R-3 H was drilled 4 m short of 6000 m with an inclination of 75° without any well control incidents. Drilling of the well was completed in 82 days, 2 days ahead of schedule. This paper will highlight some of the challenges and experiences of drilling HAHPHT subsea wells. As this paper is written Kristin has finished drilling of 4 high angle HPHT wells and 2 low angle wells.
Investigation of a Smart Steamflood Pattern to Enhance Production From San Ardo Field, California
Authors: Mamora D. D. , Sandoval J. E.
Published: December 2007

We have investigated the use of a novel smart steamflood pattern in San Ardo field, California to minimize steam override and thus enhance oil production and reduce steam injection costs. The smart steamflood pattern consists of a vertical injector placed at the center of the pattern and a smart horizontal producer placed on each of two (parallel) sides of the pattern. The horizontal section of the producer is fully open initially, but after steam breakthrough only one-third (heel-end) is kept open.

Using an 8-component thermal compositional model, we compared the performance of the smart steamflood pattern (under steam- and steam-propane injection) against the conventional 9-spot inverted pattern in the Lombardi reservoir, San Ardo field. A 16×16×20 Cartesian model was used to represent one-quarter of the typical 10-acre pattern in the field. Main results of our investigation are as follows.

First, under steam injection at 1200 BPDCWE, oil recovery after eight years is significantly higher with the smart steamflood pattern (61% OOIP) compared to that with the conventional steamflood pattern (51% OOIP). Second, when steamflooding follows cyclic steam injection, the smart steamflood pattern recovers 53% OOIP in eight years compared to 46% OOIP with the conventional pattern. Lastly, steam-propane injection accelerates the first oil production peak by 10% and the second by 24% when compared with pure steam injection using the smart steamflood pattern.
A Simple Model for Annular Two-Phase Flow in Wellbores
Authors: Hasan A. R. , Kabir C. S.
Published: December 2007

Annular flow is associated with production from both gas-condensate and geothermal wells. Oil wells also experience it during high-GOR production. The current mechanistic modeling approach entails estimation of film thickness before computing frictional pressure-drop as gas flows past the wavy-liquid film surrounding the pipe wall. This study probes to discern this film thickness and its impact on pressure-drop computation in wellbores producing steam-water, gas-condensate, and gas-oil mixtures.

Computational results show that the most likely value this dimensionless liquid-film thickness is less than 0.06 in annular flow. For such thin-film thickness, the computed friction factor is only slightly higher than that estimated with smooth-channel assumption. When the homogeneous model is used to compute pressure gradient by ignoring the wavy liquid film on frictional pressure-drop, good agreement is achieved with field data and those of a mechanistic model.
Log-Based Pore Volume Compressibility Prediction—A Deepwater GoM Case Study
Authors: Wolfe C. , Russell C. , Luise N. , Chhajlani R.
Published: December 2007

Pore Volume Compressibility (PVC) is one of the most important parameters for proceeding with project sanctioning. An accurate estimation of pore volume compressibility of reservoir rocks is essential for compaction evaluation, reservoir drive determination, reserves estimates, reservoir pressure maintenance, casing collapse analyses, and production forecasting. This information is then used in modeling the reservoir and calculating the economic value of the project. Thus, obtaining credible indications of this value early in the well evaluation process is invaluable. Unfortunately, this data is usually required long before a conventional core can be obtained and mechanical rock properties measured. Furthermore, cores are only available at discrete points along the wellbore requiring the data to be extrapolated to the missing sections.

To accommodate the need for this data early in the project and to circumvent the short comings of core-based information gaps in the wellbore, a cost effective approach that utilizes common wireline data is used to obtain a continuous profile of the pore volume compressibility with depth shortly after wireline logging operations have concluded. The method employs a log-based mechanical property program that simulates triaxial loading to obtain static elastic moduli as well as rock strength. The resulting rock mechanical properties are then converted into their uniaxial strain equivalents and used to determine the pore volume compressibility. The process is repeated for several drawdown stages with the condition that the deformations are contained within elastic limits. This yields the complete reservoir compaction trend as a function of reservoir depletion.

The log-based model was recently validated by comparing with lab-derived results from an offset well in deepwater Gulf of Mexico. The results indicate that the uniaxial pore volume compressibility obtained from the log-based method matches well with the results obtained in the laboratory. This fact suggests that the log-based approach should be utilized with a high degree of confidence to determine the PVC in the absence of core data, insufficient depth coverage of the cores, and/or to validate the core results.
Relative Permeability Characteristics for Supercritical CO2 Displacing Water in a Variety of Potential Sequestration Zones in the Western Canada Sedimentary Basin
Authors: Bennion B. , Bachu S.
Published: December 2007

Sequestration in deep underground formations of large amounts of CO2, captured from large stationary sources, such as power plants, oil upgraders and refineries, is one method that is under consideration for reducing greenhouse gas emissions to the atmosphere in both Canada and United States. In hydrocarbon-producing regions, such as Texas in the United States and Alberta in Canada, CO2 geological sequestration is likely to first occur in depleted or abandoned oil and gas reservoirs. However, in many regions, including oil and gas producing areas, this is insufficient because either the sequestration capacity of oil and gas reservoirs is lower than the amount of CO2 emissions from large stationary sources, or because this capacity is not available until the reservoirs are depleted. Deep saline aquifers provide a very large capacity for CO2 sequestration that is immediately accessible, and they are found in all sedimentary basins in the North American mid-continent. Proper understanding of the relative-permeability character of such systems is essential in ascertaining CO2 injectivity and migration, and in assessing the suitability and safety of prospective CO2 sequestration sites.

This paper reviews the experimental protocol and presents detailed water-CO2 relative permeability data for three sandstone and three carbonate formations in the Wabamun Lake area southwest of Edmonton in Alberta, western Canada, where four major coal-fired power plants which produce large volumes of CO2 are located. These formations are in general representative of the in-situ temperature, pressure, salinity, porosity and intercrystalline permeability characteristics of deep saline aquifers in on-shore North American sedimentary basins. The data will allow detailed numerical simulations of CO2 injection and sequestration processes both at this specific location, and for similar operations planned elsewhere and around the world.
Making Economic Decisions To Mitigate Lost Circulation
Authors: Whitfill D. , Wang H.
Published: December 2007

Proposal

Well construction optimization involves many decisions during the planning and implementation stages. One of the most difficult decisions during the planning stage—choosing the system and the approach to prevent lost circulation— becomes even more difficult during the actual drilling operation due to the "heat of battle" environment. What is generally understood is that lost circulation will be one of the major trouble costs during well construction.

In the past, a favored system or approach may have been used for most or all lost circulation incidents. However, improvements in understanding all aspects of lost circulation show that the "favored system" method is technically unwise today in view of logging-while-drilling (LWD) data and other recently developed sources of information. The delineation of fracture geometry induced during drilling, based on rock properties, may point out significant differences in the length and width and seriousness of anticipated induced fractures. Major differences in permeability between shale, sandstone and vugular limestone also show immediately that one-size-fits-all solutions are not going to be effective or efficient. These kinds of potential information need to be incorporated into any plan for controlling lost circulation.

This paper discusses models and tools to evaluate differences in the resistance of the borehole to lost circulation and also discusses the rationale for choosing a particular approach to a potential lost circulation problem. The rationale for preventative measures is also explored, along with a method to make an economic decision whether to stop drilling and treat for lost circulation or to keep drilling.
Mapping Preferential Flow in a West Texas Waterflood Using Surface Tiltmeters
Authors: Kramm R. C. , Griffin L. G. , Apruzzese J. , Stanley G. R. , Flaten D. W. , Bradshaw M. K. , Lucas B. C.
Published: December 2007

Surface Tilt Mapping (STM) has been successfully applied to stimulation treatments, disposal projects and in numerous steam floods to provide information on fluid movements in the reservoir. This proven technology has now been applied to a waterflood in the San Andres formation at a depth of 5600 feet to analyze preferential flow. Since typical water injection rates in the San Andres range from 100 to 300 BWPD, a novel flowback method was developed to maximize the STM response when testing injection wells under normal operating conditions. An analysis technique that allows the removal of earth tides was also applied to further enhance the quality of the data. The STM results showed conclusive preferential flow direction in the seven wells tested. In most wells, multiple tests were performed with good agreement on the flow trend.
Hierarchical Simulation of Multiple-Facies Reservoirs Using Multiple-Point Geostatistics
Authors: Maharaja A. , Journel A.
Published: December 2007

In reservoirs with more than three facies, a better and more geologically sound approach is to hierarchically simulate the reservoir facies. Ideally, the hierarchy should follow the sequence of deposition of the facies in the reservoir. Three alternative hierarchical approaches that honor depositional relations are applied to a synthetic fluvial reservoir consisting of four facies namely, channels, levees, crevasse splays and floodbasin. A 3D example with channel, point bar, levee and floodbasin is also presented. The results using hierarchical simulation are found to be better than those using joint simulation in terms of reproduction of large-scale structures which control flow through the reservoir.
A Semianalytical Method To Calculate Relative Permeability From Resistivity Well Logs
Authors: Li K.
Published: December 2007

A semianalytical model was developed to infer relative permeability from resistivity data. Although it would still be necessary to conduct experimental measurements of resistivity, these are easier than measuring capillary pressure. On the other hand, resistivity data are commonly available from routine well logging. The semianalytical model was tested against experimental data. The results demonstrated that the relative permeabilities calculated from resistivity data were close to those calculated from capillary pressure data. The model developed in this study may also provide an approach to estimate permeability using both the resistivity well logging and well testing.
ESP Model Implementation and Result Analysis Under Gas/Liquid Flow Conditions
Authors: Sun D. , Prado M.
Published: December 2007

The one-dimensional model proposed by Sun and Prado [1, 2] to predict Electrical Submersible Pumps (ESP) head performance under gas-liquid flow conditions has been improved with a new correlation for the ratio of the drag coefficient (Cd) to an interfacial characteristic length ( rinterfacial ). This study has found the ratio, Cd / rinterfacial, is also a function of channel rotational speed in addition to gas void fraction and other parameters. The paper summarizes the model with detailed wall frictional equations and addresses its implementation procedure from a manufacturer's available single-phase catalog data to the predicted two-phase head performance results. The implemented algorithm is especially effective to obtain the ESP head performance under two-phase flow conditions. The study is beneficial for the appropriate design, simulation, and troubleshooting of ESP installations in a two-phase environment.

The model has been used to compute results and perform sensitivity analysis under different two-phase flow conditions: pump intake pressure, gas void fraction, gas flow rates, rotational speeds, Cd / rinterfacial, and wall friction effects, respectively. The sensitivity analysis has been used to determine the correlation for the ratio of Cd / rinterfacial during model development.

The comparison of the model results against the experimental data, except at a low gas void fraction with a low liquid flow rate, shows good agreement. The new model gives an excellent prediction for different shaft rotational speeds compared to Zapata's partial gas-liquid data of ESP [3]. However, further validation with more experimental data is needed.
Microseismic Fracture Mapping Optimizes Development of Low-Permeability Sands of the Williams Fork Formation in the Piceance Basin
Authors: Wolhart S. L. , Odegard C. E. , Warpinski N. R. , Waltman C. K. , Machovoe S. R.
Published: December 2007

Williams Production Company performed a study to improve hydraulic fracturing and field development in the Williams Fork Formation, Piceance Basin, Colorado. The Williams Fork Formation is part of the Mesaverde Group and consists of massively stacked low permeability sandstones. Wells in the Williams Fork are usually stimulated in multiple fracture stages using limited entry techniques. This paper describes how hydraulic fracture mapping was performed with microseismic imaging on two wells in the Grand Valley Field and two wells in the Rulison Field. This was part of a pilot project to assess well downspacing and to assist with stimulation optimization. Fracture length was longer than expected but varied somewhat by field, well and treatment type. Payzone coverage was good considering significant differences exist in breakdown and pore pressures of the various sands within the hydraulic fracture stage. Fracture initiation and early growth did not fully correlate with pore pressure and ISIP data from diagnostic injections but overall payzone coverage generally matched this data.
Environmental Biodegradation and Drilling Performance of Water-based Polyampholyte Drilling Fluid
Authors: Wysocki S. , Bielewicz D. , Knez D.
Published: December 2007

Some of drilling fluids are a mixture of many components including organic as well as inorganic polymers. In order to assure stable parameters and the required technological parameters of drilling fluids, all components must be resistant to downhole conditions. At the same time it would be beneficial if the drilling fluids were biodegradable after the drilling process. As such they would have less of an environmental impact and would be easier to utilize. Organic polymer-based drilling fluids are efficient and environmentally-acceptable, but sensitive to biodegradation so they are treated with biocides. The treatment adds toxicity and makes the waste fluid difficult to dispose off [1]. The challenge in polymer fluid fomulation is to reduce biodegradation of active (while drilling) fluid and increase biodegradation of the waste fliud. Presented in this paper is a study of drilling properties and environmental performance of fluid based on newly synthesized ampholyte polymer.

Drilling performance of the new fluid was evaluated with regard to rheology, filtration, salt and temperature resistance. Samples of the fluid were tested using API Standard Methods.

Environmental study addressed the fluid biodegradation. Biodegradability was investigated using Merck method. The Merck method uses testers with agar surfaces. The bacterial count/ml of the sample is determined by comparing the density of the colonies appearing on the slide with densities shown on the model chart.

The results were compared to results for fluids with starch agents.

The results show that polyampholytic-starch fluid is biodegradable by bacteria but still has good and stable rheological parameters and filtration.

The findings show the advantages of polyampholytes and drilling fluid with polyampholyte components and provide some perspectives for industrial implementation.