bluuebunny/crossref_metadata_2025 huggingface dataset:
Using Wireline Formation Evaluation Tools To Characterize Coalbed Methane Formations
Authors: Schlachter Greg
Published: December 2007

Wireline formation evaluation tools have been used for over 50 years in conventional formations to acquire formation pressures, permeability, fluid samples and many other reservoir characteristics. These same wireline tools have now been used successfully to characterize coal bed methane (CBM) formations in Alberta, Canada.

Field case studies indicated that conventional pressure transient analysis can be used to interpret CBM wireline formation pressure draw down and build up transients. Downhole optical tools were used during pump out to predict formation fluids in place and determine in situ critical desorption pressures.

This method of formation characterization offers a potentially superior and more complete method of acquiring CBM formation properties than more traditional injection fall off tests. Ambiguities caused by fall off testing can be caused by inflation of coal cleats and fractures, multi-phase permeability and well bore storage.

Formation pressures, permeabilities, in situ critical desorption pressure and formation fluid type are important reservoir properties in CBM plays as in any hydrocarbon bearing formation. Traditional methods of injection fall off data acquisition may be cost effective but difficulties in data quality and interpretation may not justify the initial cost savings.
CO2 EOR From a North Michigan Silurian Reef
Authors: Toelle Brian , Pekot Larry , Mannes R. G.
Published: December 2007

The Charlton 30/31 field, located in the northern reef trend of the Michigan Basin was developed within the stratigraphie unit historically referred to as the Niagaran Brown. The field covers 300 acres with a structural closure of approximately 300 feet and produced 2.6 million Bbl. of oil during its primary production. A total of 6 wells were drilled during the 1970′s to produce the field. This reservoir is a low porosity, low permeability limestone matrix with irregular dolomitized intervals of higher porosity and permeability. Core Energy selected this field for enhanced oil recovery (EOR) using CO2. The source of the CO2 is a nearby natural gas processing plant which removes the CO2 from the produced gas stream of local Antrim Shale formation production in order to meet pipeline quality specifications.

To monitor the flooding of this reef a full field study is being conducted which includes earth model construction, reservoir simulation with history matching and the acquisition of a 4D seismic survey. This study is being funded by the US Department of Energy and the first 3D survey has been acquired. Basic and advanced geophysical analyses were performed on this initial 3D survey. These included wavelet extraction, well to seismic tie generation, horizon interpretation, seismic variance analysis and investigations into a number of other seismic attributes. The results of this interpretation along with the well data were used in static model construction.

Reservoir simulation was performed using this static model and a 25-year production history. During preparation of the field for injection, it was discovered that the reservoir had been an inadvertent dump-flood with water from the overlying Dundee formation, entering the reef through corroded well casings. This significantly complicated the forward reservoir simulation that was used to predict how the CO2 would flood through this reservoir.
Injection of Seawater and Mixtures With Produced Water into North Sea Chalk Formation: Impact on Wettability, Scale Formation and Rock Mechanics Caused by Fluid-Rock Interaction
Authors: Puntervold Tina , Austad Tor
Published: December 2007

Seawater has been injected into high temperature and natural fractured North Sea chalk reservoirs to improve oil recovery with great success. Previous studies have shown that seawater will improve the water wetness and cause enhanced compaction of the matrix. The composition of the produced water will be quite similar to initial formation water at the start of the water injection. The formation water contains various amounts of divalent cations like Mg2+, Ca2+, Sr2+, and Ba2+. Later on, the composition will change due to the interaction between seawater and the chalk formation and some mixing with formation water. The fluid rock interaction will involve dissolution of CaCO3, substitution of Ca2+ by Mg2+ at the chalk surface, precipitation of CaSO4, SrSO4 and BaSO4 depending on the reservoir temperature. Because of environmental reasons, it is desirable to re-inject produced water together with seawater. In the forthcoming research, we will study experimentally the effect of this re-injection on oil recovery and chalk compaction by using mixtures of produced water and seawater as injection fluid. Based on model studies using the OLI-software package, the compatibility of mixtures of produced water and seawater has been studied at different temperatures by looking at the precipitation of CaSO4, SrSO4 and BaSO4. Also the impact of changes in the concentrations of Ca2+ and Mg2+ due to surface substitution is modelled. The results are discussed in terms of possible scale formation in the producer and injector. In addition, actual chemical equilibrium reactions in the chalk matrix are discussed in relation to variation in temperature during continuous injection of seawater. Special focus is made on wettability modification, irreversible thermodynamics, and impact on the mechanical strength of the chalk matrix.
CO2-Enhanced Oil Recovery Potential of the Appalachian Basin
Authors: Bank G. C. , Riestenberg D. , Koperna G. J.
Published: December 2007

The Appalachian Basin states of New York, Pennsylvania, Ohio, West Virginia and Kentucky have a long, rich history of oil production, with current estimates of cumulative oil production at approximately 3.5 billion barrels of oil. However, estimates of the original oil in-place (OOIP) in the region's mature oil fields suggest that nearly 14 billion barrels were in-place prior to the beginning of production more than a century ago. Although early production data are often "best guesses", the remaining oil in place in this Basin appears to be on the order of 10 billion barrels. Without new efforts, this oil may remain permanently "stranded" following secondary recovery efforts and field closure.

One manner by which a portion of this stranded resource can be recovered is through the use of carbon dioxide enhanced oil recovery (CO2-EOR). The merits of CO2 miscible flooding are well documented and have been demonstrated for more than 30 years in Texas’ Permian Basin, with CO2-EOR efforts currently increasing in the Gulf Coast and the Rocky Mountain Basins. With the current strong oil price situation, the oil producers in the Appalachian Basin may be interested in the CO2-EOR potential in the Basin.

This paper follows a series of reports entitled "Basin-Oriented CO2-EOR Assessment" of the United States1 with an assessment of the Appalachian Basin oil producing states of New York, Pennsylvania, Ohio, West Virginia, and Kentucky. Reservoir simulation using detailed, respresentative data from major oilfields throughout the region indicate that 1,230 million barrels may become technically recoverable if advanced CO2-EOR technology is utilized. The economically recoverable resource will depend on future oil prices and CO2 costs.
Global Seismic Inversion—A New Approach to Integrate Seismic Information in the Stochastic Models
Authors: Guerreiro L. , Caetano H. , Maciel C. , Real A. , Silva F. , Al Shaikh A. , Al Shemsi M. Ali , Soares A.
Published: December 2007

Classical geostatistical inversion methods perform a sequential approach where acoustic impedance (AI) values are generated in a seismic trace by trace basis (Bortolli et al, 1993, Haas A. et al, 1994, Grijalba-Cuenca et al, 2000). These methods need a priori knowledge of areas of poor seismic quality, otherwise false "good" correlations between synthetic and real seismic can be artificially imposed.

A new version of the stochastic seismic inversion algorithm (Soares et al, 2006) was recently applied to a complex Middle East carbonate reservoir to evaluate the robustness and efficiency of the new methodology. This reservoir, located onshore Abu-Dhabi, comprises a strong progradational internal geometry with several clinoforms which amplify the internal complexity of the reservoir and have a strong impact on well production.

This iterative methodology is based on global simulations and co-simulations of AI. The process generates several intermediate models. Those that contribute more to achieve an objective function are used to condition the simulations of the next iterations. There is no local imposing of artificial good fit, as it happens in most trace-by-trace approaches. Spatial dispersion and main patterns of AI are reproduced at the final AI cube. Another important advantage of this technique is that the final images reflect the quality of the seismic data through the uncertainty associated to the final seismic impedance cube.

Despite the scarcity of the log data and the small area of the pilot zone compared with the total volume of the entire seismic cube, the proposed method achieved extremely satisfactory results. Both synthetic seismic data and the seismic acoustic impedance cube captured the main local geologic features of this complex reservoir. Final local correlation coefficients, measuring the match between synthetic and real seismic, can be viewed as a measure of the local uncertainty associated to the areas of good and poor seismic.
Optimal Grid Coarsening: A Fast Proxy for Large Reservoir Optimization
Authors: Mamonov A. V. , Couët B. , Bailey W. J. , Prange M. , Djikpesse H. A. , Druskin V.
Published: December 2007

Reservoir simulation models often require grids sufficiently resolved to capture the complexities of the geological structures present so that pressure and saturation profiles are deemed reasonable enough for decisions to be made with confidence. However, high resolution often implies long simulation run times, which is compounded in optimization problems. Reservoir optimization problems usually involve localized decisions, e.g., production control for a specific time-dependent objective function. With this tighter focus on optimization objectives, the reservoir simulator can often be replaced by an approximate proxy function, e.g., decline curves, neural networks and polynomial response surfaces. This accelerates the run time, allowing the optimizer to make more calls to the simulator, but at the cost of simplified physics and some consequent loss of accuracy.

Recent work in numerical solutions of partial differential equations (PDE) by Druskin and Knizhnerman (2000) introduced a finite-volume optimal grid approach to improve solution accuracy of linear PDEs at targeted points of a computational domain. This approach was applied to the solution of electromagnetic and acoustic forward and inverse problems arising in oil exploration and medical imaging. We extend this work to non-linear PDEs by introducing a reservoir simulator that is used as its own proxy. We distinguish our optimal grid from an optimal upscaling in that it may not preserve local features of the model, but will preserve some aggregate objective value used in production optimization. This narrow focus allows greater coarseness than a properly upscaled grid by replacing the fine-grid model with a coarser grid whose coarsening is determined by an optimizer that preserves the accuracy of a predefined aggregate objective value.

In this work we optimize injection and production rates to maximize the field oil production total (FOPT) over a fixed period of time. The proxy optimizer will seek the best coarsening that preserves this objective value over a range of injection/production rates for each well. The resulting coarse-grid model has a similar physical behavior in these output values to that of the fine-grid model. The grid coarsening problem is a non-linear discrete optimization problem, where the optimizer adjusts the grid coarsening while preserving the fine-grid response of interest. Although we focus on FOPT here, other reservoir objectives can also be handled.
Fracturing Mechanism and Fracture Systems Analysis of Fractured Carbonate Reservoir from Abu Dhabi, UAE
Authors: Sirat M. , Salman S. M. , Bellah S.
Published: December 2007

Many fractured carbonate reservoirs of Abu Dhabi have different structural styles and exhibit unpredicted behavior for development-production realizations. We have studied one of these reservoirs that comprise a domal structure with very gentle dipping flanks, and high fractures density. These fractures play an important role in controlling fluid flow and recovery.

In this study, we present a conceptual model that explains the fracturing mechanism; formation, development and reactivations of these fractures. It also provides answers to questions about the main factors that control fracture geometries and densities with respect to reservoir structure and rock typing. Based on the available data from 2D seismics and cores examination, fracture systems identification and classification were carried out. We have also discussed the relationships between these fracture systems with curvature, faults and shear zones.

We believe that fracturing mechanism is mainly controlled by reactivations of the pre-existing basement faults (structural grain), which have been reflected throughout the sedimentary cover as two main fractures systems each of which comprises three fracture sets: one extensional and two conjugate shear ones. It is evident that curvature of doming whether on the crest (convexity) or on the flanks (concavity) have no major effect on fracture densities. Instead, fracture densities increase in the vicinity of faults or shear zones. Fracture densities also increase in dolomitic layers compared to limestones and anhydrates.

This new fracturing concept has a significant impact on production and recovery, where different scenarios for fractures opening/reactivations due to the present state of stresses are presented.
High Resolution CT and Pore-Network Models to Assess Petrophysical Properties of Homogeneous and Heterogeneous Carbonates
Authors: Youssef S. , Rosenberg E. , Gland N. , Kenter J. A. M. , Skalinski M. , Vizika O.
Published: December 2007

Carbonate rocks often present complex pore-structures involving multiple porosity systems with various interconnectivity degrees. These pore-systems, from microporosity to vugs/fissures, drastically affect petrophysical properties. Pore network models are well suited to calculate petrophysical properties of rocks from pore space structure information. The predictability of such models depends on the accuracy with which the complex geometry and topology of the pore network are captured. Computed MicroTomography (μCT) produces 3D images of the porous medium at the micron scale thus giving the opportunity to describe quantitatively and with a high precision the geometrical and topological characteristics of the 3D pore space. By providing a full description of pore space connectivity and geometry, such studies promise to improve both the understanding of diagenetic overprint and predictability of pore network models used to calculate petrophysical properties of these porous media.

This methodology is applied to a set of rocks with various heterogeneity degrees from the Tengiz buildup (Precaspian Basin). The Tengiz central platform contains a succession of cyclic shallow water deposits ranging from Famennian to Bashkirian in age. The distribution of reservoir rock-types in this depositional zone is determined by a combination of primary deposition and burial diagenetic modification and includes spatial variations of both porosity enhancing as well as porosity filling effects. A pilot study using pore-network modeling from μ-CT imagery of several selected samples resulted in spatial pore and pore-throat size distributions, level and type of pore interconnectivity. Porosity, permeability and capillary pressure were calculated from μ-CT analyses and show a close match with those derived from measurements. Most strikingly, μ-CT allowed the extraction of 3Ddistribution of pore type and connectivity as well as cement types, information essential to reservoir quality assessment but very difficult to reconstruct using the classic petrographic approach. These models can be used for rock-typing, up scaling, to extrapolate petrophysical properties to uncored wells and to investigate new phenomena like evolution of properties due to dissolution/precipitation inherent in CO2 injection.
Progress in Immiscible WAG Modelling
Authors: Skauge A. , Dale E. I.
Published: December 2007

The paper reviews recent development in modelling of immiscible WAG processes (IWAG). Several different approaches have been made to model three-phase relative permeability in particular. In most cases capillary pressure has been neglected in application of these models in numerical simulations of IWAG. The argument behind eliminating capillary pressure is to simplify the model, and the assumption that capillary pressure is of less importance for the problem analysed or because there are no experimental data available. This study also shows the consequence of neglecting capillary pressure.

A novel approach to include three-phase capillary pressure is discussed, and also a procedure for estimation of three-phase capillary pressure from more available two-phase capillary pressure data. A practical case study of history matching IWAG core floods is also presented.
Evaluating the Efficiency of Near Neutral Pickling Fluids
Authors: Mofunlewi Samuel S. , Uchendu Ugochukwu
Published: December 2007

With continuous efforts to introduce new technologies for wellbore cleaning, a near neutral pH pickling fluid has been evaluated for use as a pickling fluid. Pickle treatments are done to improve well productivity by removing various contaminants from well tubulars in an efficient and cost effective way.

Traditionally, iron oxides and hydroxides scales in tubular are removed with weak HCl (typically 5–15%). However, the use of acid as a pickling fluid has become a deterant to operators since they pose safety and environmental handling risks. The disposal of the spent acid is also very costly due to its corrosive nature (pH<0).

Laboratory evaluation has shown that, near neutral pickling fluid has a better derusting effect than HCl. It gives a phosphate coating at the metal surface delaying it from further reoxidation. The pH of the fluid before and after treatment was found to be 5.90 and 6.20 respectively making it more safety and environmentally friendly than the traditional HCl. Field application of the fluid has shown it to be 8% more economical than HCl.

This paper will discuss details of our laboratory analysis and findings. Case histories of this fluid shall also be discussed.
Technology Based Formation Damage Control & Mitigation Measures in the SINCOR Zuata Field, Venezuela
Authors: Nnabuihe Larry , Couzigou Erwan , Chan Albert , Solana Alberto
Published: December 2007

The poor productivity and abnormal productivity decline in some SINCOR horizontal wells in the Faja field could be traced back to drilling and well completion practices. The wells were drilled with solid-free XCD mud and completed with slotted liners. Drilling operation is characterized by severe mud losses. The wells were brought into production without wellbore cleanout to remove the drilling mud induced damage. The wells produce Extra Heavy Oil (EHO). The observed trends since the start-up of production was indicative of the skin damage magnitude.

An in-house review in 2005 adopted an approach that included acquiring and extending information derived from cores and reservoir fluids, laboratory analysis data, drilling, well completion/well test results, and production data. X-ray diffraction studies show that the formation contains about 8% of clay minerals which comprise mostly kaolinite (~85%) with traces of illite and smectite. The damage mechanisms identified included fines migration, the swelling of reactive clay minerals, physical blockage by unremoved filter-cake masses, water-block resulting from massive leakoff of aqueous mud filtrate, the wax crystallization and asphaltene precipitation blockage.

Engineering work and technology-based solution which encompass diagnosis of damage mechanism, laboratory testing, formulation and optimization of treatment fluids, job design and field execution procedure were carried out to mitigate the formation damage. The surfactant-diesel based (SDB) treatment design and application has yielded great successes in removal of formation damage, resulting in a high incremental oil production with job payback time of 3 – 24 days. Evaluation of the two SDB treatment campaigns conducted in 2005/2006 revealed that water-block with its associated high Interfacial Tension against the EHO constitutes a serious impediment to oil productivity.
Achieving Nigeria's Gas Flares-Out Target: Challenges and Implications for Environmental Sustainability and Global Climate Change
Authors: Igbatayo Samuel A.
Published: December 2007

Following Nigeria's global acclaim as a dominant crude oil producer and exporter, the nation's natural gas industry has demonstrated a huge potential as a strong player in the emergent global natural gas market. Although Nigeria is yet to explore directly for gas, as most of its gas discoveries are incidental to production of crude oil; the nation has one of the largest natural gas reserves in the world. Currently estimated at about 187 trillion standard cubic feet, Nigeria's natural gas reserves are rated amongst the top ten largest in the world. Distributed evenly between associated and nonassociated gas, most of the nation's natural gas production has been flared or re-injected to enhance greater crude oil recovery. However, gas flaring is accompanied by considerable environmental degradation, particularly in the Niger Delta, where the bulk of the nation's oil and gas resources are found. Also, Nigeria has been blamed for the emergent global climate change through its green house gas emissions. This has serious consequences for both regional and global environmental sustainability. Consequently, the nation's policy makers decided to capture the economic benefits associated with Nigeria's huge stock of natural gas and stem the damaging tide of environmental degradation. This development has informed the nation's gas flare-out target set for 2008, and imposed on the nation's oil and gas industry. Therefore, this paper provides a holistic framework for attaining the nation's flare-out target and ensuring compliance with elimination of global greenhouse gas emissions.
Managing Pipelines Risk in Nigeria
Authors: Awonusi Samuel
Published: December 2007

In Nigeria today, there are networks of pipelines cris-crossing the entire nation. These lines are used to transport hydrocarbon from the oilfields to the terminals and LNG plants. They are also used to move products from petroleum refineries or petroleum receiving jetties to product depots in the downstream sector.

Pipelines risks are negative and undesirable factors that could erode the benefits of safe movement of hydrocarbon products cheaply and efficiently through these pipe networks. These risk factors are increasing by the day with the changing complexities of the Nigerian society.

There are three keys drivers that drive the management of risks associated with pipeline transportation. These are economic benefits to users of pipelines, corporate social responsibility on the part of companies (multinationals) to their employees and third parties; and government regulations.

The consequences of the attendant poor management have been loss of thousands of lives to fire outbreak on exposed pipelines, pollution of the environment, loss of earning power and scarcity of refined petroleum products in the country.

Applying the HEMP process, it is the intention of this paper to take a critical look at pipelines associated risks, assessment of the risks taking into consideration current realities in the country and what controls are required to safeguard the pipelines, people and the environment in Nigeria.
Impact of Structural and Stratigraphic Heterogeneities in Deep Water Development
Authors: Onyeagoro Kachi , Naruk Steve , Van der Vlugt Frans , Barton Mark , Pirmez Carlos , O’Byrne Ciaran
Published: December 2007

Recent successful exploration and production programs in deepwater settings worldwide have increased the need to better understand the range of structural and stratigraphic depositional complexities and their impacts on performance and sweep efficiency. As oil and gas companies explore and produce hydrocarbons in deeper water settings, and in their quest to produce hydrocarbons from difficult or unconventional reservoirs, there is a need to develop innovative ways of achieving success and reducing the overall cost – an enabler to remaining competitive and profitable.

First generation deep-water production in the Gulf of Mexico was from well imaged, structurally and stratigraphically simple fields, penetrated by multiple wells and producing at high ultimate - high recovery rates with gradual pressure declines. A second-tier of deep-water fields in the Gulf of Mexico, Deep-water Nigeria and Brazil are structurally and stratigraphically complex and are posing more challenges to cost efficient development. A poor initial understanding of the distribution and impact of these heterogeneities has led to unforeseen compartmentalization issues within these second-generation deep-water reservoirs.

One of the key challenges in the development of structurally and stratigraphically complex fields is to realistically translate geological and reservoir engineering data into parameters that can be used to assess and mitigate compartmentalization. Many structural and stratigraphic features that do not define pressure compartments prior to production become significant barriers to flow during production, necessitating the drilling of more wells to increase recovery from the field. Clearly the ability to make early predictions on when and where such barriers occur and their effectiveness during a production lifecycle can be key to successfully developing second generation fields in deepwater settings.

The importance of answering these questions and realistically characterizing and quantifying structural and stratigraphic heterogeneities has been demonstrated in many deepwater fields. These characterizations have yielded more accurate and better-defined well paths of highly deviated and horizontal wells across faults and different stratigraphies, robust field development plans with clear economic advantages, and successful history matches.
Tuning the Analytical Model for Better Prediction of Recovery Factor
Authors: Akpara Kingsley
Published: December 2007

Recovery factor is one of the key determinant variables for establishing reservoir description in reservoir modeling. Existing analytical solutions postulate the use of average reservoir and pressure dependent parameters to estimate static recovery. At start of field development, prediction of recovery factor could sometimes be misleading because insufficient data is used to tag the economic value of the field. Though this practice is necessary to quantify the profitability of the venture, it is advisable to apply reservoir simulation for detailed description of the reservoir hence better dynamic prediction of recovery.

This paper therefore, investigates an excellent idea that improves estimation of recovery by using dynamic parameters; dynamic in the sense that better understanding of the reservoir character changes the initial perception of its properties. This idea recognized the mathematical model by Arps et al, but the modification here is that post history matched reservoir initial properties are inputs in the correlation, resulting to changes in the multiplicative and exponential constant. With this, one could investigate segment, zones and cell contribution to recovery.
A Didactic Analysis of Water Cut Trend During Exponential Oil-Decline
Authors: Lawal Kazeem A. , Utin Emmanuel , Langaas Kåre
Published: December 2007

While a number of methods, including semi-log/linear plot of water cut versus cumulative oil and water-oil ratio versus cumulative oil, have been published for extrapolating water cut during oil decline, the challenges of internal consistency, accuracy and limited areas of application have remained unresolved. These make the application of the methods threatening to the associated estimates of oil reserves and investments on water-handling facilities.

In this paper, based on an investigation of internal/practical consistency and the physics of fluid flow, a didactic analysis of water cut models derivable from popular oil rate models of Arps, Li and Horne, as well as the Flowing Material Balance is carried out. This culminated in the development of an internally consistent water cut model, applicable during exponential decline of oil production. The development supports an exponential function of oil-cut vs production time.

Using both hypothetic and field examples, applicability and performance of the derived model are demonstrated, and compared with six of the popular water cut models, including those of Ershagi and Omoregie, Liu, Warren and Purvis. Besides its simplicity, the proposed model consistently performs better and shows robustness.

Although the form of the proposed model is here limited to exponential oil rate decline, the principles can easily be extended to other oil production decline trends.
An Experimental Investigation of In-situ Combustion in Heterogeneous Media
Authors: Awoleke Olurotimi G.
Published: December 2007

An extensive literature exists on the nature of the reactions that occur when air comes in contact with crude oil during in-situ combustion (ISC); however the effect of reservoir heterogeneity on the ISC process has not been experimentally addressed in prior studies. This paper presents the results of recent experimental efforts to shed more light on ISC. We probe the effect of pressure, temperature, injection flow-rate, and matrix properties on the combustion of a Middle-Eastern 19.7° API oil in a tight-formation sand. The experimental perspective includes both oil oxidation kinetics and combustion-front dynamics in a 1-m long combustion tube. Most importantly, geological effects on the ISC process are investigated by incorporating various degrees of porous medium heterogeneity in the combustion tube runs. From the experimental data, pre and post burn CT scans of the combustion tube, and postmortem analyses, we deduce the effect of both small and large-scale heterogeneities on the spatial and temporal propagation of the combustion front.

Specifically, kinetic runs show typical ISC behavior consistent with oxidation and good reactivity of the oil-rock system. It was observed that the supply pressure, injection flow-rate, the reservoir matrix and a metallic additive significantly affected the performance of this particular system. Better combustion resulted from greater oxygen partial pressures and by using the reservoir rock as compared to an artificial sand-clay mix. The combustion tube runs indicate that the process of in-situ combustion can be successfully implemented in a reservoir with small-scale heterogeneities (a few inches) and may be challenged by much larger scales (feet).
Effect of Sugar on the Thickening Time of Cement Slurries
Authors: Bermudez Marta
Published: December 2007

Sugar is widely recognized as a cement retarder by the drilling industry and has been used in cementing operations where cement returns are expected on surface.

Experts disagree about the effect that sugar has on cement slurries, a few believe that it acts as both an accelerator and a retarder depending on the concentration, but the majority believe that the sugar acts as a retarder only.

Lab tests of thickening time and compressive strength were conducted using different concentrations of sugar. The results indicated that the sugar acts as a retarder of cement slurries when added in small concentrations and as an accelerator when added in high concentration.

The compressive strength tests showed that the accelerated slurries developed very little or no compressive strength, indicating that no hydration of the cement grains occurred. The retarding mechanism of the sugar is well documented, but the acceleration effect is not widely known. An attempt was made to explain the mechanisms involved in the shorter thickening time and lack of compressive strength observed at high sugar concentrations.

These project findings are of great practical importance to the drilling industry. Sugar is currently used in the field with the idea that it will always retard the slurry.
Enhanced Coal Bed Methane Recovery Using Nitrogenase Enzyme
Authors: Vishnukumar Joshi Neeti
Published: December 2007

As per the present-day scenario, energy consumption is increasing by 5.6% per annum, so it is today's requirement to extract more efficiently from currently available reservoirs and to find novel energy resources. Coal Bed Methane (CBM) is one such non-conventional hydrocarbon resource, which is easily extractable. This paper focuses on Enhanced Coal bed Methane Recovery using biogenic enzymes for increasing secondary recovery. The primary recovery of CBM is nearly 50 % (Jichun Zue et al, 2003) and the conventional secondary recovery using gas injection technique is around additional 6-8%. This paper introduces the concept of Enhanced Coal bed Methane Recovery using biogenic enzymes for increasing secondary recovery. Here, use of thermostable Nitrogenase enzyme is suggested to fix the injected nitrogen as a compound for enhancement in secondary recovery of the Methane. The enzyme can be generated in biochemical plants using ‘Nif’ gene as a microbiological tool. The Nitrogenase Enzyme is immobilized for longer activity. The immobilized enzyme, which is then injected into the well bore suspended in the proper medium. This paper provides systematic approach and relevant theoretical explanation for the proposed technique, which is suggested for the first time.
Technical-Economic Modeling of CO2 Sequestration Considering Injection in Mature Oil Fields
Authors: Ravagnani A. T. F. S. Gaspar
Published: December 2007

The oil industry with its technological developments and tools may help to alleviate the greenhouse gases emissions into the atmosphere. The CO2 injection in oil reservoir as an agent for EOR (Enhanced Oil Recovery) has a dual benefit. This technology can improve to recover oil that is not produced through natural methods anymore, besides to store CO2 in the reservoir for thousands of years avoiding it reach the atmosphere, through the technology known as CO2 sequestration. It consists on the capture of the gas from an anthropogenic source, its compression and transportation to the oilfield. This work presents a technical-economic methodology to evaluate the feasibility of the process in a hypothetical mature oilfield. It considers a cash-flow model besides a sensitivity analysis considering the main components such as revenues, investments, operating costs, taxes according Brazilian fiscal regime and the carbon credits to be earned due to the project. The methodology takes into account the quantification of emissions and energy used in the process, emphasizing the technology contribution to the environment.
Gel Preparation and Properties Control for Operations in Pipeline Transport
Authors: Akhiyarov Denis
Published: December 2007

It is well known that the main means to transport large amount of crude oil, oil products and natural gas on a long distance are pipelines. Generally the pumped fluids contain paraffin, asphaltic-resinous components that deposit debris at certain conditions together with solid mechanical impurities. This debris layer on the pipe surface is constantly increased which leads to the decreasing of the flow area. The latter can be restated as reduction of effective diameter. To prevent or reduce the effects of deposits formation mechanical, chemical, thermal and combined removal methods are employed. Gel systems are included into combined method of pipeline cleaning. This technology is named as gel pigging. Gel pigs have also other applications in pipeline systems: isolation (sealing) of pipeline section under pressure, carryover of gas and water accumulations, pulling of the devices that got stuck, series fluids separation, treatment of wall surface with chemicals.

The approach in the project is to compose a new gel formulation which is dragged along the pipeline and form a thin layer on the bore surface that function as hydraulic friction reduction remedy due to smoothing of pipeline wall surface and dampening of turbulent pulsations, heat insulator due to gelling of fluids with low heat conductivity and foaming of the gel, internal corrosion protection means due to separation of metal wall from the transported fluid. Anticorrosion chemical additives may be inserted to provide required protection, wax deposition prevention due to paraffin crystals' adhesive forces reduction on the gelled layer surface. To accomplish all these, the thin gel layer should be able first to deposit and then not to erode under hydrodynamic and cohesive forces. Also viscoelastic rheological properties of certain gel compositions are being analyzed on rotational rheometers to compose suitable composition for operations of isolation, pigging, separating and layering.

As a future work interaction of deposited paraffin and gel is going to be investigated that is essential information for gel pig volume estimation.
Risk Assessment of a Dynamically Positioned Drilling Operation
Authors: Thorogood J.L. , Bardwell K.S.
Published: December 2007

Quantitative risk assessment is used to estimate the probability of a loss of well integrity as a result of a station keeping failure when drilling with a dynamically positioned unit. The key factors affecting station keeping reliability are identified and some publicly available data are presented. The analysis indicates the relative importance of certain variables and reviews the extent to which they may be controlled by the designer.

P. 435
Friction Analysis for Long-Reach Wells
Authors: Aadnoy B.S. , Andersen Ketil
Published: December 2007

Presently wells are drilled in the North Sea approaching a horizontal reach of 8 km. Plans for the near future is to extend these towards and beyond 12 km. Well friction is one of the most important limiting factors in this process.

Torque and drag prognosis are today developed on in-house simulators. Although a good tool for planning, improvements are made on an trial and error basis, and, these simulators have limited availability. To provide more insight into the frictional aspect, a larger study was undertaken. Explicit analytical equations are derived to model drill string tension for hoisting or lowering of the drill string. The equations are developed for straight sections, build-up sections, drop-off sections and side bends. Both constant curvature models and a new modified catenary model are derived. The new catenary model is developed for arbitrary entry and exit inclinations. Equations to determine well friction in fully 3-dimensional well profiles are also given. Furthermore, based on the tension equations, expressions for torque and drag are developed. Equations for combined motion and drilling with motor are also given. Using these equations, the total friction in a well is given by the sum of the contributions from each hole section.

A field study offshore Norway is included in the paper. Using the equations derived in the paper, the well path is chosen to minimize the torque on the rig, which is the limiting factor. The paper also summarize a number of guidelines for extended-reach well design, and shows the design of an ultra- reach well of more than 12 km reach.

P. 819
Field Validation of Swab Effects While Tripping-In the Hole on Deep, High Temperature Wells
Authors: Rudolf R.L. , Suryanarayana P.V.R.
Published: December 2007

In an earlier paper by the same authors (Kicks Caused by Tripping-In the Hole on Deep, High Temperature Wells), it was suggested that a combination of high temperature and high trip-in speeds could result in a secondary swab effect large enough to cause underbalance and subsequent well control incidents. Field validation of the earlier work is reported in this paper. A deep, high temperature well, similar to the ones discussed in the previous paper was chosen for the field validation. Field measurements of pressure, temperature and trip speeds were taken while tripping in the hole. The experimental procedures, data gathering, and analysis are described in this paper. Field data were compared to the predictions of a swab-surge model and remarkable agreement was found. The secondary swab effect was clearly measurable, and its magnitude compared very favorably with the model predictions. This increases the confidence in model results and the concept that kicks can result from tripping in the hole at high velocities. It is concluded that secondary swabs while tripping-in is an important design consideration for deep, high temperature wells. Underbalanced conditions can occur if the trip speeds are high, and if the mud weight is not compensated for the effects of high downhole temperature. Swab-surge models similar to the one used in this study can be used in the design phase to avoid kicks while tripping-in by determining maximum trip-in velocities and the effect of temperature and pressure on the effective density of the drilling fluid.

P. 835
New Criteria for Gravel and Screen Selection for Sand Control
Authors: Tiffin D. L. , King G. E. , Larese R. E. , Britt L. K.
Published: December 2007

Guidelines for sand control completion technique and gravel size selection are presented. These new criteria are based primarily on reservoir sand size distribution. Emphasis is on formations with very high fines content and a wide distribution of grain sizes. Upon failure and/or particle movement, these formations can exhibit very high skins and reduced production capacity with traditional control methods. Guidelines are also discussed for formations with little fines and a very uniform grain size distribution.

Proposed criteria are based on field experience and experiments conducted with reservoir cores from different sand formations worldwide. Experiments were conducted by "packing" different gravels at the effluent end of core plugs and surging fluids through the plugs and gravel. Cases are presented where traditional methods would lead to an overly restrictive gravel pack and advantages are obtained with use of larger gravel.
Mechanisms of Sand Control Screen Plugging From Drill-In Fluids and its Cleanup Using Acid, Oxidizers and Enzyme Breakers
Authors: Ladva H.K.J. , Parlar M. , Price-Smith C. , Fraser L.J. , Ali S.A.
Published: December 2007

This paper describes mechanisms of sand control screen plugging from a range of drill-in fluids and proposes methods for minimizing plugging damage. A series of laboratory tests were performed to illustrate the importance of selecting the correct drill-in fluid, cleanup procedure and/or breaker type to give maximum productivity in a horizontal, non perforated open hole completion. The effectiveness of hydrochloric acid, oxidizing agents, and enzyme breaker in increasing the mud cake and formation permeability was investigated by targeting specific mud components in the mud cake and invaded formation. The role of drill solids and breaker effectiveness was also investigated on filtercakes produced from laboratory and field muds. An effective breaker may thus be selected for a required change in permeability of the mud cake and removing damage from the formation for optimum productivity.

To identify whether the critical damage occurs at the screen or the formation during flowback, a series of dynamic filtration tests were performed using a consolidated sandstone and different water based muds. This was followed by cake cleanup using hydrochloric acid and finally flowback through the formation and different screen types. The effect of whole mud on different types of sand control screens was also investigated and recommendations are made for the field procedures to minimize screen plugging.

In addition to the laboratory testing, pilot plant scale tests were carried out using a synthetic-based drilling fluid to illustrate effective screen cleanup through the correct wash fluid and cleanup procedure.

P. 229
Technique for Fluid-Loss Control and Enhanced Cleanup
Authors: Dewprashad B. , Cole C. , Coats C. , Soybel J.
Published: December 2007

In deep-well, high-permeability completions, effective control of loss of expensive, brine completion fluid is a major challenge. High bottomhole temperature, differential pressure, and brine acidity may limit the reliability of conventional fluid-loss control agents that are available for less severe conditions. Gel pills generally cannot control high-density brines because it is difficult to generate a stable gel pill in a high fluid-density environment, thereby complicating placement efficiency. Par-ticulate-type systems may also be undesirable because of cleanup concerns.

This paper describes the codevelopment and field application of a nonparticulate, high-density fluid-loss control material consisting of derivatized hydroxyethylcellulose (DHEC) and an enhanced external breaker system. Development of the product was critical to the successful completion of the first-ever, three-phase, triple-stacked subsalt completion in the Gulf of Mexico (GOM). DHEC provides an effective method of controlling high-density brine loss during deep-well, high-permeability completions, with minimal formation damage. Within a certain temperature range, DHEC is stable in zinc bromide (ZnBr2) brines for extended periods. The enhanced acid breaker system allows the user to achieve rapid breaking of DHEC on demand. The paper also discusses the principles underlying the design and development of the material and the accompanying breaker system. The paper presents the laboratory data that helped us evaluate crosslink times, temperature stability, break times, and regained permeability. In laboratory tests, DHEC showed potential to effectively prevent loss of 17.2-lb/gal ZnBr2 brine for up to 36 hours at 215°F. Afterward, the breaker system broke the DHEC within 30 minutes. After this cleanup procedure was applied, the test cores had retained an average of 90% of their original permeability. In actual field applications, the fluid-loss material effectively controlled 17.2-lb/gal ZnBr2 in a GOM subsalt well while the operator used fracpacks to complete three separate zones in the same well.
The Role of Taylor Vortices in the Transport of Drill Cuttings
Authors: Philip Zeno , Sharma Mukul M. , Chenevert Martin E.
Published: December 2007

Taylor vortices, i.e., toroidal rings, are formed in an annulus when one pipe is rotated inside another. These rings form when the critical rotation rate (rpm) is reached. Equations are presented to calculate the critical rpm above which Taylor vortices form for both Newtonian and power law fluids. The theoretical computations show that under typical drilling rotation rates Taylor vortices do form.

Experiments were conducted with a wide range of Newtonian and power law (shear thinning) fluids in a transparent annular geometry. The experimental values of critical rpm are in agreement with computed ones. Taylor vortices were clearly observed to form and did contribute to the lift of simulated drill cuttings.

In Newtonian fluids, the lifting capability increased as the viscosity was increased. For power law (shear thinning) fluids, contrary to expectation, the lifting capability decreased as the apparent viscosity was increased. This was because increasing the polymer concentration in order to increase apparent viscosity also lowered the ‘n’ value of the fluid. Fluids with low ‘n’ values exhibit lower velocities close to the stationary walls. It can be inferred, therefore, that with regard to the transport of cuttings (by vortices or otherwise), high ‘n’ value fluids are more efficient.