bluuebunny/crossref_metadata_2025 huggingface dataset:
Time-Dependent Behavior of Drilling Fluids Under Cyclic Temperature and Pressure Loads
Authors: Piber M. , Prohaska M. , Hublik G. , Thonhauser G.
Published: December 2007

Drilling fluids are subjected to cyclic pressure and temperature loads when circulated in the wellbore. However, little information exists about quantitative changes of fluid viscosities during long-term circulation. Therefore the effects of temperature/ pressure cycles on viscosity reduction/ regaining for different Xanthan products - dissolved in pure solutions and in drilling mud - and for Bentonite fluids are evaluated in a laboratory study. To model these cyclic temperature/pressure loads a new HPHT cyclic load test has been developed and the impact of temperature and time dependent viscosity on hydraulics calculations is evaluated quantitatively.

First, the ability of Xanthan and Bentonite fluids to break and reestablish viscosity under cyclic temperature and pressure loads was evaluated. Furthermore it was investigated whether fluids are able to build up original viscosity after applying cyclic temperature and pressure loads. This effect is defined as viscosity degradation per load cycle which could be quantified as part of this work. Bentonite, in contrast to Xanthan fluids, however has a different, more complex and stronger time and temperature dependent viscosity behavior when cyclic loads are applied. For the investigated fluids a significant impact of time dependent behavior under cyclic temperature and pressure loads on hydraulics modeling is shown.

By performing the new test procedures it is possible to quantitatively determine cyclic viscosity degradation. When using these findings, the accuracy of hydraulic modeling and nozzle optimization can be improved. Better predictions of critical viscosity breakdowns and additive requirements to maintain fluid viscosity can be done.
Hydrocarbon Production Forecast and Uncertainty Quantification: A Field Application
Authors: Rotondi M. , Nicotra G. , Godi A. , Contento F. M. , Blunt M. J. , Christie M. A.
Published: December 2007

Realistic reservoir models are essential for efficient field management and accurate forecasting of hydrocarbon production. Such models, based on the physical description of the reservoir, need to be calibrated or conditioned to historical production data. The process of incorporating dynamic data in the generation of reservoir models, known as history matching, is traditionally done by hand and is a very tedious, time-consuming procedure that, in addition, returns only one single matched model. It has been shown that the best matched model may well not be a good predictor of future performance.

In this work, one of the first field applications of the Neighbourhood Algorithm (NA) is presented. The NA is a stochastic sampling algorithm that explores the parameter space, finds an acceptable ensemble of data fitting models and extracts robust information from this ensemble in a Bayesian framework. The aim is to forecast hydrocarbon production accurately and to assess the related uncertainty by means of multiple reservoir models.

The NA methodology was extensively applied to an offshore gas field and compared to a previously manually matched model. The Mistral field has been producing for 6 years from 7 wells. Gas and water productions and pressure data were available and the uncertainty quantification was consistently obtained. Algorithm control parameters and objective function definition effects were investigated. The posterior probability density functions of each unknown parameter, calculated taking into account the observed production data, were evaluated. The hydrocarbon production was forecast using Bayesian inference and the economic risk estimated. The overall process was carried out with a significant time reduction compared with the previous manual approach.

The results presented suggest that use of stochastic sampling techniques in a Bayesian framework may well be a valid alternative methodology to the traditional industry workflow for the uncertainty quantification in producing fields.
Successful Application of Glass Reinforced Epoxy (GRE) Casing in Hydraulically Fractured Water-Injection Wells
Authors: Peralta D. , Maggioni A. , Garcia R. , Martin D.
Published: December 2007

This paper describes the successful application of Glass Reinforced Epoxy (GRE) casing in 1,100-m water injection wells in Puesto Hernandez field, Argentina.

Prior to running 5 1/2-in. casing, thorough testing was carried out to evaluate the actual performance during frac treatments using a surface-mounted model. Other tests were designed and carried out to evaluate casing behavior during running, cementing and perforating operations.

Operational aspects, such as the effect of buoyancy, cement logging and downhole tools are addressed, as well as solutions and proposed approaches to remaining problems.

To date, four wells have been completed with this technique. Results indicate that casing, tools and operational techniques are appropriate and represent an innovative, sound alternative to reduce maintenance costs associated with scaling and corrosion.
Technology Implementation to Enhance Reserves Recovery in Mature Fields Requires a New Business Model Between Service Companies and Operators
Authors: Ross D. A. , Kalfayan L. , Smith K.
Published: December 2007

According to worldwide hydrocarbon production statistics, mature fields produce approximately 70 percent of global production. Average recovery rate from these mature fields worldwide is only 35 to 37 percent. The rate is even lower in the U.S.: Of the 609 billion barrels of original oil in place estimated by the U.S. Department of Energy (DOE), 351 billion barrels is thought to be unrecoverable by existing technology. To meet the ever-increasing demand in worldwide hydrocarbon production and avoid energy crisis situations, the oil and gas industry needs to substantially increase recovery factors associated with mature fields.

Current business models among operators and service providers have greatly restricted the ability to implement traditional and emerging technologies required to enhance the performance and extend the life of mature fields. During the past decade, the industry has increasingly depended on service providers to develop new technology. Meanwhile, service providers must recoup technology development investments in a relatively short period because of the short-term economic objectives and expectations dictated by the investment community.

New oil and gas fields have different economic drivers than mature fields; new field economics often justify the use of new technologies and field-wide engineering projects to maximize production and profit, whereas mature field economics (and current business models) limit technology implementation and focus on single-well solutions.

To complicate matters further, both operators and service providers often lack personnel resources to strategically implement full-scale field management programs with the objective of optimizing recovery efficiency. Frequently, one-off remedial treatments are performed without a proper field-wide objective in mind.

A new approach can ensure better use of technology in exploiting mature fields. This approach between service provider and operator incorporates a strategy to restructure the service cost basis and better balance risk and reward associated with technology utilization.
Development and Commercial Deployment of an Expandable Monobore Liner Extension
Authors: Stockmeyer C. F. , Tillman D. L. , Weirich J. B. , Sehnal Z.
Published: December 2007

For a number of years, the exploration and production industry has sought to prove the feasibility of monobore expandable liner extensions as an advantageous alternative to conventional casing designs. Included as part of the initial casing design, the goal of an expandable monobore liner extension is to enable the operator to drill deeper exploration and production wells with larger hole sizes at the reservoir. As a contingency plan, the goal is to enable the operator to isolate zones that contain reactive shales, sub-salt environments, low fracture gradient formations or other drilling situations without having to reduce the casing and subsequent drilled hole size into the reservoir. A one-trip, top-down expansion system was developed and tested to prove the feasibility of the expandable monobore liner extension concept, including the ability to provide an optimized, cost-effective casing configuration without reducing drilled hole size. During the development process, the need for expandable open-hole packers or optional cementation of the liner was identified and addressed. This paper details the development process for the expandable monobore liner extension system, including testing and the resulting commercial field deployment in an operator well to qualify the technology.

This paper will demonstrate the challenges faced during various planning and execution stages and explain how those challenges were met, specifically in the following areas:

Pre-planning wellbore design options and considerations Monobore liner extension selection, one-trip system reliability System qualification Zonal isolation requirements Field installation considerations Expansion process Safety and environmental impact Post deployment results
Characterisation and Modelling of a Fractured Reservoir Using a Novel DFN Approach
Authors: Gouth F. , Toublanc A. , Mresah M.
Published: December 2007

Characterising and modelling of naturally fractured reservoirs (NFR) with fracturing at different scales is usually a challenging task as the specific response from each scale is difficult to isolate.

We focus on a carbonate reservoir in North Africa, in production for two years. There is evidence of fracturing at different scales (from diffuse fractures to conductive faults) with significant implications for oil production.

We first present the way fractures have been fully characterised using an extensive integration of static (FMI) and dynamic (Well test, Pressure Build Up, Mud losses) data. The advanced use of well test signatures in understanding the main flow mechanisms occurring within the reservoir is emphasized.

Then, we detail the way the dynamic model was build using a novel discrete fracture network (DFN) approach developed internally. The method populates the static parameters at the full field scale using a geo-statistical process guided by a geological driver. Using an innovative technique (the Elementary Patch), a fast calculation of fracture permeability in each grid cell and automatic calibration on the well test data can be made. We also discuss how the best choice for the simulation model (single porosity vs double porosity) depends not only on the fracture-to-matrix permeability ratio but also on the magnitude of the shape factor and on the production mechanism. The final dual porosity–dual permeability model integrates the intermediate scale fractures implicitly and the conductive faults explicitly whereas the smallest scale is discarded as it has a negligible impact.

In summary, we present a complete and innovative workflow process for a geoscience study on NFR and demonstrate its application in a real case study. The need for full data integration to achieve a comprehensive understanding of the flow mechanisms involved during production is underlined.
Polymer Powder/Cement Composites
Authors: Chougnet A. , Audibert A. , Lecolier E. , Moan M. , Guichard B. , Mazard C. , Valenti A.
Published: December 2007

The selection of an optimal cementitious material is critical to maintain zonal isolation for the lifetime of oil and gas wells not only for primary cementing but also for well abandonment. Polymer powder/cement composites present good mechanical and durability properties since polymer latex promotes improved adhesion and flexibility to the hardened cement paste. So, for oilwell applications, which require high durability under aggressive environment, polymer powder/cement composites would be good candidates. During the well completion phase, the slurry placement strongly depends on its rheological behaviour that is studied here for polymer powder/cement composite suspensions: they present a shear-thinning behaviour in permanent shear and a transition from a gel to a liquid behaviour in oscillatory shear. The replacement of cement particles by polymer particles induces a decrease of the viscosity in the liquid state and of the storage modulus in the gel state. The good quality of the polymer particle dispersion and their high affinity for cement particles were observed by SEM and cryo-SEM. Solid state NMR (29 Si and27Al) and DSC help to understand the influence of the polymer addition on the hydration/hardening. Depending on the temperature and on polymer chemistry, it may strongly influence the hydration reactions of the materials and their kinetics. All these results help us to understand the relations between the slurry composition, its rheological behaviour and the properties of the hardened materials.
The Search for Alternatives to Screen: Is Permeable Cement a Viable Option?
Authors: Vidick B. , James S. , Drochon B.
Published: December 2007

The search for a cost-effective alternative to screens has been intensive in the sand control field. Different systems have been proposed in the past, including various solutions based on permeable cement, but none of them have made a real breakthrough.

This paper presents a new permeable cement system that has significant advantages over previous systems. In particular, this permeable cement was formed in a one-stage process, eliminating the need for a subsequent treatment to generate permeability. This permeable cement system also has adequate strength and sufficient permeability for several sand-control applications. However, the durability of the permeable cement was evaluated and found to be poor. Some suggestions are made for possible applications of the permeable cement.
Correcting Common Errors in Probabilistic Evaluations: Efficacy of Debiasing
Authors: Welsh M. B. , Begg S. H. , Bratvold R. B.
Published: December 2007

‘Debiasing" refers to techniques taught during risk and uncertainty training that enable trainees to avoid or reduce errors arising from cognitive biases. We discuss current techniques and their applicability to oil and gas decisions.

To test the debiasing efficacy of sitting a general decision making course, engineering students completed a survey [1] designed to test for the well-known overconfidence and anchoring [2] biases both immediately prior to and following a short course on the psychology of decision making containing sections on cognitive biases and debiasing. No feedback or specific training was included in the course, - which described debiasing techniques for various cognitive biases including those tested within the battery.

Participants' results on the overconfidence task showed a 21% improvement in calibration – from 27% to 48%, indicating a significant impact of knowing about biases and debiasing methods on susceptibility to overconfidence. However, no improvement was seen in participants' performance on the anchoring task.

The first result, taken in conjunction with findings from Welsh et al [1], suggests that training in dealing with uncertainty, and knowledge of the modes of action of cognitive biases, can reduce overconfidence but that this benefit is reduced as time since training increases. The second result, again in conjunction with previous findings [1, 3], suggests that training alone is insufficient to overcome the anchoring bias in isolation from domain specific knowledge. That is, to reduce the adverse effects of the anchoring bias, trainees need to be both trained in debiasing techniques and possess knowledge about the field in question such that they can apply the debiasing techniques to their knowledge.

We use these preliminary, experimental results to highlight and inform discussion regarding the potential benefits of debiasing. Specifically, we argue that the efficacy of debiasing within oil and gas decision making requires further research – in particular, a longitudinal study to track the efficacy of debiasing over time. We conclude that an understanding of the potential and limitations of training in debiasing techniques will allow management to formulate effective strategies for the introduction and maintenance of debiasing training to reduce the impact of errors arising from cognitive biases. Additionally, it is argued that introducing future industry personnel to these concepts during their university studies will ease their integration into industry practice
The Role of Enhanced Production Logging Measurements in Challenging Openhole Horizontal Completions
Authors: Mukerji P. , Zaouali Z. , Rees H.
Published: December 2007

The keys to proactive production and reservoir management are production logs that profile fluid entries and diagnose problems in producing wells. Designing optimal production strategies and remedial operations requires high-confidence diagnosis. Production logging in high angle and horizontal wells producing mixtures of various phases is challenging because of complex flow regimes.

In this paper we present a field example that uses a new compact, integrated production-logging tool that incorporates the latest technological advances and best practices to address complex production-logging requirements. We are able to demonstrate the added value in terms of comprehensive flow diagnosis.

A production logging operation using the new tool, which specializes in horizontal and deviated well logging, was planned to obtain key inputs for the reservoir model and investigate reasons for low well productivity. Production logs from the new tool resulted in accurate flow diagnosis and led to better understanding of complex flow mechanisms across the horizontal section. These enhanced measurements were integrated with borehole imaging information leading to a better understanding of flow contribution from the matrix and fractures.

The tool provides a recording of holdup and velocity profiles along the vertical diameter of the borehole cross-section. Three sensor arrays, consisting of six optical probes, six electrical probes, and five spinners, are spread across the wellbore on retractable arms that can be opened and closed with a hydraulic sub to better locate holdup interfaces. The optical probes use the fluid's reflectance to derive the gas holdup, and the electrical probes measure the fluid's impedance to derive the water holdup. The spatial location of the different sensors is accurately known through the use of an integrated relative bearing sensor and a caliper measurement. The direct measurement of the velocity and fluid holdup enhances the capability of the analyst to determine an accurate downhole flow profile.
An Organized Approach: Challenges Faced by Today's New Engineers in the Petroleum Industry
Authors: Edwards J. T. , Woo G. T.
Published: December 2007

Today the knowledge gap between the "seasoned professional" and "new hire" to the petroleum industry has reached a new level of disparity. Due to market trends and job availabilities in prior years, many engineers have been turned away from futures in oil and gas. But with the current global demand for energy at an all time high, companies are now looking for fresh faces to fill their empty seats.

It is not out of the norm for a new engineer to step into a role and see a dramatic split among his peer group of engineers. Many of those in the industry today have on average 10 to 15 years experience working in the oil and gas industry, which reflects the time of the last major market upswing. The challenge arises in bridging generational as well as technological gaps to allow for quality job performance and precise communication among varied experience levels of engineers.

In navigating the new profession, the right questions need to be asked by the young engineer. Nothing can be assumed or taken for granted. No matter what role the engineer holds in the disciplines of drilling, completions, reservoirs, or operations, a level of responsibility will be assigned but we must ensure it comes with clear definitions and expectations.

There is not always a choice of tasks or even the luxury of transition periods in today's oil and gas industry. More positions are becoming available each day with a smaller pool of applicants who poses the desired years of experience. This forces companies to fill openings with many candidates fresh from college and in some instances, with minimal hands-on experience. This paper will be a guide for today's new engineer with suggestions for how to succeed in this essential global industry.
Water Shutoff Treatments Using an Internally Catalyzed System in Boscan Field: Case Histories
Authors: Mata F. , Ali S. , Cordova Ernesto
Published: December 2007

This paper describes the results obtained using an Internally-Catalyzed System1 (ICS) to reduce water production in the Boscan oil field, near Maracaibo, West Venezuela.

This field is divided in two blocks: north and south. In the south block, wells can eventually produce oil with 90% water cut, due to the influence of an aquifer. The accumulated production per well can be as high as 6 (six) million barrels, and typical rates range from 600 to 2,400 BFPD (barrels of fluid per day).

In order to mitigate the high water cut and water production, the operator implemented in 1998 a water shut-off (WSO) program. In 2003, the ICS was introduced as part of this program. The ICS is solids-free and internally activated. It is used for permanent zone plugging, and lost circulation control, delivered into the matrix of the targeted zone. Laboratory evaluations were conducted to determine effects on the hard setting of ICS, resulting from the contact between ICS and other fluids deployed on well construction, and well production enhancement, as well as reservoir fluids, acids, cement filtrate, brines, formation water and crude oil.

This paper summarizes the results of 19 WSO jobs performed. . In some specific wells, water cut decreased by 20%; on others, by 70%, with consequent oil production increase in some cases of more than 400 BOPD per well. The WSO treatments have been designed for deeper formation penetration, and long-lasting water blockage. Applied WSO treatments with ICS have been found to effectively block water production over a long period. Cost of treatments has been paid out within approximately 45 days.

This paper includes laboratory tests, operational procedures and results for each treatment done with ICS technology, demonstrating to be an excellent option to enhance oil recovery on mature fields with water high water production.
In-Field Emulsion Treatability Test With the Electrostatic Susceptibility Tester
Authors: Lee J. , Frankiewicz T. , Ismail M. Z. , Anwar M. L. , Samad M. S. A.
Published: December 2007

An Electrostatic Susceptability Tester (EST) was used to determine the treatability of oil emulsions from the Miri Crude Oil Terminal (MCOT). In the EST, a sample of heated, chemically treated emulsion is exposed to an AC/DC electrostatic field and the energy and time required to coalesce water droplets and separate water from the oil emulsion are determined. Both fresh emulsions from the trunk lines to the plant and aged emulsion from a holding tank at the terminal were tested. It was concluded that electrostatic treatment is effective for treating the fresh emulsions at 50 °C with the injection of either acetic acid or emulsion breaker. The dry oil BS&W was reduced from 2.5 vol% to 0.3 vol% when acetic acid injection rate was increased from 250 ppm to the range of 500-1000 ppm. The naturally occurring surfactant (calcium napthnate) that stabilized the emulsion tends to dissolve into the oil phase at higher acetic acid concentrations, thus making the emulsion easier to be treated. Electrostatic treatment is not as effective for treating the aged emulsion from the holding tank because the emulsion contained greater than 40% water and was apparently stabilized by a combination of calcium napthenate and fine, oil-wet solids.
A Multidisciplinary Approach to Hydraulic Fracturing in the South Texas Wilcox Formation
Authors: Britt L. K. , Smith M. B. , Haddad Z. , Lawrence P.
Published: December 2007

The objective of hydraulic fracturing is to design and execute a fracture stimulation that achieves the desired fracture dimensions (length & conductivity) to maximize well productivity and reserve recovery. In order to truly achieve this objective information from the geosciences and engineering disciplines are required.

Geologic, geophysical, and petrophysical data are needed to understand reservoir quality, thickness, and extent. Reservoir engineering data is used to assess in-place hydrocarbons, flow capacity, permeability, and reservoir drainage area. Production decline analysis is used to assess reserve recovery and corroborate in-place hydrocarbons and flow capacity. Rock mechanics is used to assess the elastic properties of the formation of interest, bounding sediments, as well as the fracture mechanics. Finally, completion and stimulation engineering are used to design, execute, and evaluate the hydraulic fracture treatment. All of these data and disciplines are needed to truly optimize the fracture stimulations, production rate, and reserve recovery.

In recent years, there has been much discussion regarding the causes for, or reasons that the dimensions of the hydraulic fracture are shorter and less conductive than desired. These causes include: relative permeability effects1, fracture fluid cleanup2-5 and gel damage6-12, multi-phase and non-Darcy flow13-15. In addition, reservoir heterogeneities, layering, and boundaries can result in less than optimal dimensions as well. These effects have been investigated; however, without the integration of quality multi-discipline data determining the inter-relationship or causal relationships of these effects is difficult. As a result, the factors truly affecting the fracture dimensions may be misinterpreted or misrepresented resulting in less than optimal results.

This paper will document a multi-discipline investigation of a multi-well South Texas Wilcox Field used to improve and optimize hydraulic fracture treatments in the area. The integration of this dataset will be used to determine fracture dimensions and assess the critical parameters for the creation of optimum fracture dimensions.
Bokor—A New Look at Sand Production in a Mature Field
Authors: Kasim A. , Wijnands F. , Subbiah S.
Published: December 2007

Although the stacked reservoirs of the Bokor field, offshore Sarawak, Malaysia are prone to sand production, the field development team did not a-priori opt for gravel packs in every well. While such completions can indeed eliminate sanding risk, the team also wanted to consider the impact of the completion on the production rate of a well. The optimum completion not only excludes sand, after all. It also maximizes hydrocarbon production.

We carried out a geomechanics and sand production study, using readily available data. The paper gives an insight in the physics of sand production and how this process can be geomechanically modeled. It shows how the model is used to select feasible completions and quantify sand-free production rates, over the life of the reservoir.

One important outcome was that screenless completions were possible in the deeper reservoirs by optimizing perforation orientations. Apart from other advantages of screenless completions, this leads to significant potential increases in sand free production rates.

An integrated Sand Management process brought together geomechanics, petrophysics, reservoir and completion engineering to truly optimize completions.
Effective Gas Shutoff Treatments in a Fractured Carbonate Field in Oman
Authors: Ali E. , Bergren F. E. , DeMestre P. , Biezen E. , van Eijden J.
Published: December 2007

A giant fractured carbonate field in north Oman has both complex geology and complex reservoir drive mechanisms. The upper densely fractured layers are produced using the gas oil gravity drainage (GOGD) process, while the less fractured lower set of layers is subjected to water flooding. The production from the GOGD layers is through vertical and horizontal wells completed in a thin fracture oil rim. Gas conformance control is a challenge in many of these wells as the gas breakthrough occurs for a variety of reasons: 1) downward movement of fracture gas-oil contact (fracture oil rim thinning), 2) gas breakthrough via high conductivity fractures (fracture gas breakthrough), 3) zonal isolation failure at the wellbore (mechanical gas breakthrough) and 4) increasing gas saturation in the matrix (matrix gas breakthrough). An integrated multidisciplinary team studied well and reservoir performance and open-hole and cased-hole logs to diagnose the source of higher than expected GOR in several GOGD wells. The most important logs in this work were MPLT surveys used to identify the sources of gas production and FMI logs used for fracture identification and characterization.

This paper illustrates the work carried out in horizontal openhole and vertical cased-hole completions in a giant fractured carbonate field to successfully shut-off the undesirable gas flow. The horizontal wells identified with poor zonal isolation behind the liner were treated with an innovative gel gas shut-off procedure. The merits of this procedure outweighed other solutions: targeted placement; a strong full-blocking gel to fill up channels behind the liner, inert particles to control fluid loss of the full blocking gel to small fractures and the formation matrix, and displacement with an already cured gel which could be washed out of the wellbore.

Significant drops in the GORs of these wells resulted in sustained oil production gains. This is a step change in the ability to manage detrimental gas production in this field and is expected to lead to further opportunities for improved gas management and well performance in this field and other fields where the GOGD recovery mechanism is used.
Mechanistic/Probabilistic Modeling of Slug Initiation in a Lower Elbow of a Hilly-Terrain Pipeline
Authors: Al-safran E. M. , Sarica C. , Zhang H. -Q. , Brill J. P.
Published: December 2007

Probabilistic/mechanistic modeling was carried out to develop a predictive model for initiated slug length distribution at the lower elbow of a hilly-terrain pipeline. Statistical analysis suggested the appropriateness of a Log-Normal model over an Inverse Gaussian model. The Log-Normal model is correlated by two empirical relationships developed for mean slug length and slug length standard deviation. Based on experimental observations, the approach of critical liquid level (instead of critical liquid volume) was adopted as the slug initiation criterion at the lower elbow. Consequently, the critical liquid level was mechanistically modeled and empirically correlated to the initiated mean slug length and standard deviation. A model validation study demonstrated the capability of the probabilistic/mechanistic models to reproduce experimental data with a satisfactory match. The match is improved when the developed correlations were tuned using the statistical confidence intervals of their coefficients.
Practical Steps to Increase Production and Reserves in Mature Gas Fields: Hugoton and Panoma, Texas County, Oklahoma, U.S.A.
Authors: Lisigurski O. , Rowe G. C.
Published: December 2007

When working in mature fields, one needs a lot of imagination because many times economic resources are limited. Workovers, that utilize proven and new technology may solve this problem. Using existing wells that already have casing, tubing, artificial lift systems and surface facilities is an excellent way to increase reserves and production with a small investment. Identifying the candidates for the workovers is the key to success.

In 2005, 43 wells were worked over in the Texas County, Oklahoma area of the Hugoton and Panoma Fields, resulting in a production increase of 2,914 MSCFD for a total cost of only $1.6 MM. Payout of the program occurred in just 4.6 months, using a conservative gas price of only $3.89 per MSCF. The techniques involved fracture stimulation, mechanical wellbore cleanouts, artificial lift type changes and acidizing. A successful workover program should apply the fundamentals of science and engineering, coupled with field operations and geology. The screening methods developed may lead to further workover activity with anticipated reserve and production increases in other areas of the Hugoton and Panoma Fields.
Improved Optimisation of Bit Selection Using Mathematically Modelled Bit-Performance Indices
Authors: Clegg John , Barton Steve
Published: December 2007

Despite the development of models describing Polycrystalline Diamond Compact (PDC) bit performance, bit selection is often made on the basis of visible, geometric features.

Bits can now be modelled routinely and described in terms of their technical interaction with the drilling assembly and the formation. Selection on the basis of modelling and this interaction is novel and valuable, and will make for more consistent selection and improved performance.

A new set of performance indices is presented for PDC bits. These are derived from a sophisticated mathematical model and describe performance in terms of:ROP – Rate of Penetration, or how fast the bit will drill for a given Weight on Bit (WOB)Durability – how resistant the bit is to abrasive wearStability – how resistant the bit is to lateral vibrationSteerability – how the bit responds to side forces and therefore how steerable it is on Rotary Steerable Systems.

Once the relative importance of each index is established, the optimal bit for the specific application can be selected.

A specialist interface is presented for Rotary Steerable Systems. Using this, the user can input system type (from the variety of systems available) and well profile, and the software will create a list of bits ranked by decreasing suitability, based on a variety of factors including some aspects of bit geometry but primarily mathematically modelled response.

The paper presents results from pilot studies and demonstrates a scientific and rational approach to bit selection – giving not only improved but also more consistent and reliable results.
An Integrated Approach to Parameterize Reservoir Models for CO2 Injection in Aquifers
Authors: Egermann P. , Chalbaud C. , Duquerroix J. -P. , Gallo Y. Le
Published: December 2007

The injection of carbon dioxide in oil and gas reservoirs (Enhanced Hydrocarbon Recovery, EHR) or in aquifers is a promising way to cope with the short-medium term issue of greenhouse gas emission mitigation. Although CO2-EHR projects represent the best economical opportunities, the CO2 injection projects in deep aquifers offer the largest capacity potential for long-term CO2 storage. The design of a CO2 injection project mainly depends on the results of reservoir models.

To be predictive, the numerical tools have to be parameterized to adequately model the multiphase flow behavior (relative permeability curves) and the phase exchanges between the injected fluids and the fluids in place (thermodynamic equilibrium). In the particular case of the CO2 injection, the potential rock/fluid interactions with the host formation must also be studied carefully as a function of the thermodynamic conditions, the fluid compositions, the rock mineralogy but also the flow regime (i.e. the distance to the well bore).

This paper presents an integrated workflow based on experiments and numerical simulations to determine in a comprehensive and robust manner the appropriate parameters at the core scale for a CO2 injection in aquifer. CO2 injection experiments were conducted under reservoir conditions. Experiment were carried out on companion plugs under several thermodynamic conditions and with different fluid systems (different brine salinities) in order to collect data (production curves and differential pressure evolution as a function of time) over a wide range of CO2 storage conditions. Then, these experiments were modeled using a compositional simulator dedicated to CO2 geological storage.

Using this approach, we show that an unique set of parameters enables modeling of CO2 injection for various thermodynamic conditions and fluid systems. Therefore, such approach leads to predictive simulations at the core scale, which contributes to the accuracy of the performance prediction of the CO2 injection at the reservoir scale, if the main geological features (heterogeneities) are included into the large scale model.
Combined Microbial Surfactant-Polymer System for Improved Oil Mobility and Conformance Control
Authors: Gabitto J. F.
Published: December 2007

Microbial enhanced oil recovery (MEOR) technologies have become established as cost-effective solutions for declining oil production. The demonstrated versatility of microorganisms can be used to design advanced microbial systems to treat multiple production problems in complex, heterogeneous reservoirs. This research project presents the concept of a combined microbial surfactant-polymer system for advanced oil recovery. The surfactant-polymer system utilizes bacteria that are capable of both biosurfactant production and metabolically-controlled biopolymer production.

This article describes the results of our laboratory work to grow microbial cultures and the work done on recovery experiments on core rocks. A bacterial strain capable of producing both surfactant and polymers has been selected. Laboratory experiments to determine under what conditions surfactants and polymers can be produced from one single strain have been conducted. Recovery experiments to determine the performance of these strains under different conditions have been carried out. Experimental results show a significant influence of nutrient regime on alternate production of surfactants or polymers for a Bacillus licheniformis strain, NIPER 1A.
Development of a Low-Frequency Quadrupole Shear-Wave Technology to Improve Quality of LWD Shear Velocity Measurement
Authors: Tang X. M. , Dubinsky V. , Patterson D.
Published: December 2007

We present the result of a new development in the logging while drilling (LWD) quadrupole shear-wave technology that was recently developed to measure formation shear velocity in the LWD environment. Due to the severity of drilling noise in the low-frequency (0-3 kHz) range, initial development focused on measurements around 4 kHz, although the quadrupole attains formation shear velocity in a lower frequency range (~2-3 kHz). The 4-kHz quadrupole data is prone to dispersion, especially when drilling with a heavy mud. The dispersion can cause uncertainties in the shear velocity measurement. Realizing the potential enhancement of the measurement, we further develop the technology to perform measurements in the 2-3 kHz range or lower. The key in this new development is enhancing the quadrupole wave energy significantly above the noise level in the designated low-frequency range. Data from this new measurement have been acquired and analyzed. Comparison has been made between the new measurement and the measurement made with the 4-kHz source. Despite the common belief that drilling noise prohibits LWD acoustic measurements toward low frequencies, we obtain quite coherent quadrupole data in the low-frequency range. More importantly, the low-frequency quadrupole shows minimal dispersion and indeed attains the formation shear velocity, in agreement with the LWD quadrupole wave theory. The new development constitutes a significant improvement in the LWD quadrupole shear-wave technology.
Analyzing and Troubleshooting Plunger-Lifted Wells
Authors: Rowlan O. L. , McCoy J. N. , Podio A. L.
Published: December 2007

Development of a new portable monitoring system has taken the guesswork out of plunger lift analysis, troubleshooting and optimization. During one or more plunger lift cycles at high sampling speeds this system acquires data from the tubing acoustic signals plus pressure recordings from both the tubing and casing. The plunger generates an acoustic pulse as it falls through each tubing collar recess when the well is shut-in. Each acoustic pulse travels through the gas in the tubing and is detected at the surface. The pulses are converted to an electrical signal by a microphone and pressure transducer. The signals are digitized, stored and processed in a computer to determine plunger position, plunger fall velocity, and plunger arrival at the liquid level in the tubing. By analyzing the collected data the operator can ensure that the plunger reaches the bottom of the tubing before the end of the shut-in time period. Setting the well's controller to have the shortest possible shut-in time period can maximize oil and gas production from the plunger lift installation. Example data collected from various plunger lifted wells are presented in this paper to show how to identify operational problems such as holes in the tubing, stuck plungers and plungers not getting to bottom.

The problem of not knowing the plunger location during the operation cycle has been overcome with this new technology by allowing the operator to see the plunger location at any time during the cycle. Having a detailed analysis of the operation of the well makes optimization of plunger lift production achievable with a minimum of effort and avoids the usual waste of time due to trial and error procedures. Knowing the plunger's location is equally important for timer-based as well as intelligent controllers, since in both cases it is necessary to make initial estimates of the appropriate shut-in time, plunger arrival time and plunger fall time. The capability to calculate the volumes of liquid and gas produced during the cycle and determining the well's inflow performance gives valuable information to determine the opportunity for increased production. Determining the position and velocity of the plunger throughout the cycle can aid in maximizing oil and gas production of a plunger lift installation.
Chemical Automation: A Part of the Well-Centric Production Optimization Loop
Authors: Lee Jaedong , Vachon Guy , Vega Patricia , Means Mitch
Published: December 2007

One of the main challenges in the oil industry is to optimize production while reducing the development costs and maximizing reserves. Real-time optimization has been gaining ground to effectively face these challenges, and has been applied in the smart or digital fields. Literature references two optimization loops, the reservoir-centric slow loop and the well-centric fast loop. Intelligent wellbores are focused on the fast loop and combine well-centric technologies with monitoring, data analysis, modeling, interpretation and automation to accelerate production, maximize recovery and reduce operating and capital expenditure costs.

As production progresses, the reservoir experiences changes in conditions, including decreasing pressure, changes in GOR and rising water cut, that will increase the possibility of corrosion, and organic and inorganic depositions in the production system. These flow assurance and equipment integrity related issues can affect the overall efficiency of the intelligent wellbores, and they should be included in the production optimization loop.

This paper discusses chemical treatment as part of the intelligent production system. Continuous monitoring and proper chemical treatment of possible sources of problems such as scale, asphaltene deposition, and oil-water emulsions closes the fast optimization loop. Closing the fast loop can be done via interventions to the well or by operation of intelligent well equipment, which allows the well to adapt to the best possible operating condition without an intervention.
Closing the Well-Centric Production Optimization Loop: Dealing with the Reservoir as an Externality
Authors: Vega P. , Vachon G. , Lee J.
Published: December 2007

With the growing demand for hydrocarbons, the need to optimize the well production and the exploitation of the reservoirs becomes critical to increase and sustain the energy supply. Intelligent Production Systems combine well-centric technologies with monitoring, data analysis, modeling, interpretation and automation to accelerate production, maximize recovery and reduce operating and capital expenditure cost. This paper presents the well as the true optimization enabler while still recognizing the interdependency between well and reservoir-centric production optimization. Once the completion is deployed and well is put in production, the reservoir becomes an externality and its optimum exploitation can only takes place through proper manipulation and operation of the well. The well-centric closed loop production optimization process involves the ability to sense the operating environment to detect and diagnose under-performing conditions and dynamically adjust production controls to maximize the well productivity. The paper presents examples of the value created by the implementation of well-centric technology.
Directional Permeability
Authors: Fanchi J. R.
Published: December 2007

A relationship between permeability tensor and coordinate orientation is used to estimate the error that occurs when some of the terms in the permeability tensor are neglected. The formula for calculating the errors that appear in the magnitude and direction of flow rate are presented. The results are applicable to any reservoir system which is influenced by directional permeability.
Dispersion Corrections Are Not Just for LWD Dipole Sonic Tools
Authors: Market J. , Canady W.
Published: December 2007

Many studies have been published showing dispersion characteristics for borehole sonic data, particularly for dipole wireline and dipole and quadrupole LWD tools. With the exception of LWD dipole tools, however, the dispersion corrections are often ignored. It is commonplace for the wireline flexural velocity to be used as the shear velocity. This substitution may be acceptable practice when dispersion correction is less than 2%. There are many cases, however, when the dispersion correction exceeds this amount and correction is necessary. The dispersion behaviour is dependent on formation properties, hole size and mud properties. There are tools issues as well - particularly the complex interaction between the resonant frequency of the formation and the frequency response of the acoustic source. Acoustic tools based on broadband sources are particularly susceptible to dispersion induced inaccuracies. For that reason, a properly implemented quality analysis program is critical to ensuring accurate shear velocity measurement.
Closing the Well-Centric Production Optimization Loop Using Intelligent Completions
Authors: Vachon G. , Vega P. , Lee J.
Published: December 2007

Smart fields technology seeks to optimize the exploitation of reservoirs. Intelligent well completions is a technology that enables this goal. It, in combination with production monitoring tools, makes production optimization possible. In this paper, we take a well-centric look at optimizing production by closing the loop from observing well behavior to determining if it is being produced optimally to making adjustments, if it is not. In order to justify the additional cost of an intelligent well, service companies must quantify how much better it will perform than a conventional installation. The paper will propose net present value as a tool for quantification and show how this benefit is realized though increased ultimate recovery, accelerated production or cost reduction. The well optimization loop has traditionally been closed by a human. As intelligent wells gain acceptance, we will move to automated systems. The paper documents how such automation will create value.