bluuebunny/crossref_metadata_2025 huggingface dataset:
Protecting Pipelines, Storage Fields, Wells and Other Facilities From Encroachments
Authors: Abbott Kevin C. , Bagnell Nicolle R. Snyder
Published: December 2007

Protecting pipelines, storage fields, wells and other facilities such as compressor stations, measurement and regulation stations and meters from encroachments is critical to all participants in today's natural gas industry. Unless this basic infrastructure is protected, the industry cannot fulfill its fundamental mission of delivering natural gas safely and reliably.

In the past, most major pipelines, wells, and surface facilities were located in remote locations and there was little chance of encroachments on those facilities. Today, however, the proliferation of development in and around major population centers has combined with the higher demand for natural gas service in those areas to increase the potential for conflict. At the same time, stricter regulation of pipeline has required natural gas pipeline companies to be ever more vigilant in protecting their facilities.1

This paper will explore what natural gas companies can do to protect their facilities and how the courts have reacted to those efforts.
Advances in the Production Mechanism Diagnosis of Gas Reservoirs through Material Balance Studies
Authors: Oscar Morán O. , Fernando Samaniego V. , Jorge A. Arévalo V.
Published: December 2007

The concept of diagnosis used in this paper has a similar meaning as it used in well test analysis, and essentially refers to the identification, and its sequence as the exploitation time increases, of the production mechanisms of a gas reservoir.

This paper discusses an approach for the diagnosis of the gas reservoir production mechanism, derived from a general gas material balance equation (GGMBE), that considers the possibility that the reservoir could be naturally fractured: z/p vs (z/p)Gp. This diagnosis of the production mechanisms can be especially very useful for conditions where the reservoir characterization is limited. Once this diagnosis process has been accomplished, the original gas in place (OGIP) can be more accurately estimated through the present methodology, especially when combined with the available techniques (specific graphs, such as p/z vs Gp, Havlena and Odeh, etc.). In addition, this method allows the estimation of the cumulative effective compressibility, ce(p), of the associated water volume ratio, M, and of the water influx, We(t). The new method is illustrated through its application to the most discussed gas field behavior examples published in the literature, among them the McEwen's water influx case, the volumetric Begg's case and the overpressured Duggan's Anderson L case.
Drilling Underbalanced in Hassi Messaoud
Authors: Moore D. D. , Bencheikh A. , Chopty J. R.
Published: December 2007

The Hassi Messaoud field, discovered in 1956, is the largest oilfield in Algeria, covering about 2000 km2 and currently including over 1000 wells. Production is from a thick, Cambrian age sandstone, at a vertical depth of approximately 3400 m. This sandstone is extremely hard, abrasive, and slow to drill. Sonatrach introduced Underbalanced Drilling (UBD), primarily in an effort to improve penetration rates, though the possibility of other benefits from UBD experienced elsewhere, such as improved production characteristics, was also acknowledged. Several factors requiring special consideration were addressed from candidate selection to equipment and procedures. The combination of depth and required bottomhole circulating pressure approach the limits of what is achievable with concentric gas injection, the only locally available UBD technology. The methods used in conducting this project are good examples of how to approach and successfully execute such a project.
Cased-Hole Pseudo-Density Logging to Distinguish Clinton Sandstone From an Associated Non-Reservoir Carbonate
Authors: Holsclaw Steven S. , Martin Jason G. , Rubin William L.
Published: December 2007

Columbia Gas Transmission operates a 290-well underground gas storage field in north-central Ohio. The Weaver storage field, converted to gas storage starting in 1937, utilizes the Silurian-age Clinton sandstone as the storage reservoir. Clinton sand thickness, reservoir quality, areal distribution and lateral continuity are often highly variable over short distances. Many of the storage wells have only cased-hole electric logs, primarily a gamma ray with an API neutron. Stratigraphic correlation and identification of Clinton sand members can be problematic, particularly when relying on cased-hole logs and original completion records.

Compounding the task of Clinton sand correlation in the northwestern portion of the Weaver storage field is the depositional presence of "Red Rock", an iron-bearing carbonate identified through x-ray analysis as an Ankerite [Ca(Fe, Mg, Mn)(CO3)2]. Over ten square miles of Red Rock with a thickness of 10 feet or greater have been isopach-mapped. Historically, the Red Rock presents a clean, blocky gamma ray signature on electric logs with an associated neutron response similar to a gas-filled sandstone reservoir. In portions of the Weaver storage field, the Red Rock was often miscorrelated as Clinton sand and mistakenly completed in numerous wells. This resulted in an undesired division of the hydraulic stimulation between Clinton reservoir sand and non-reservoir rock. Also, due to a significant iron presence, completion acids may have reacted negatively when exposed to the Red Rock to produce iron precipitates that can degrade well performance. Accurate correlation of both Clinton sand and Red Rock carbonate, therefore, is crucial to the operational success of Weaver storage field.

To address this problem in cased-hole workover candidates, a pseudo-density logging technique was used in conjunction with an API neutron log with considerable success. This logging methodology could have additional cased-hole applications where contrasting behind-pipe porous sand with associated or enveloping carbonate is desired.
MudCap Drilling When? Techniques for Determining When to Switch From Conventional to Underbalanced Drilling
Authors: Medley George , Stone C. "Rick"
Published: December 2007

Throughout the planning and hazard analysis phases of unconventional drilling techniques, one question continues to arise: When is it appropriate to switch from conventional drilling to underbalanced operations?

The one condition that must exist before choosing an underbalanced operation is first encountering a need for the application of the technique. That the problem cannot be solved using conventional, less expensive means must also be determined. In many fields with no historic use of underbalanced techniques, one or more attempts to solve the problem utilizing conventional techniques are carried out until those methods are shown to be ineffective.

When the appropriate conditions have been satisfied, several other criteria exist that affect the decision to make the switch from conventional circulation to underbalanced methods, including Safety, Economics and Logistics.

Using data and examples from MudCap Drilling (MCD) scenarios from around the world, this paper demonstrates the process and techniques that have been utilized to successfully determine when the critical point has arrived to make the switch.

The development of a simple flow chart that can be utilized at the field location in making the determination to switch based on satisfaction of pre-determined criteria is also demonstrated.

Work and presentations to date have concentrated on answering the questions of ‘Why’ and ‘How’ to perform various underbalanced operations, with very little emphasis on ‘When’ to perform the underbalanced operation. While this answer is often self-evident, in many cases there is substantial leeway in determining what conditions should be present. This is particularly true when the "Why" has no bearing on preventing formation damage.
The Relationship Between Petroleum Economics and Risk Analysis: A New Integrated Approach for Project Management
Authors: Lewis Derrick , Guerrero Victor , Saeed Saad , Marcon Michael F. , Hyden Ron
Published: December 2007

Proposal

Generally, today's oil and gas projects are complex, high-risk, multidisciplinary ventures that require careful planning and precise implementation. A large number of interrelated factors and unforeseen (operational, technical and/or financial) events determine a drilling, completion, or work-over project's economic feasibility and ultimate success. Fundamental to the success of all project management is extensive economic modeling and risk analysis, since economic drivers and operational methods are developed from these processes.

This paper will discuss the development of a new analytical technique that will systematically and intuitively overcome the hurdles mentioned previously while not compromising result sophistication. A variety of underbalanced drilling examples will illustrate its efficiency. This method will allow the end user, whether novice or expert, to quickly and effectively assess economic feasibility and risks.
Bottomhole Pressure Control During Pipe Connection in Gas-Dominant Wells
Authors: Nygaard Gerhard H. , Vefring Erlend H. , Fjelde Kjell Kåre , Nævdal Geir , Lorentzen Rolf Johan , Mylvaganam Saba
Published: December 2007

To obtain an underbalanced pressure condition, nitrogen gas can be injected into the drillstring. Simultaneous injection of liquids and gases leads to a highly dynamic flow system. During pipe connections, pressure transients can cause the bottomhole pressure to rise above the pore pressure of the reservoir or fall below the reservoir collapse pressure. Migration of gas during pipe connection and in-flow from the reservoir will also cause bottom-hole pressure changes.

This paper presents a methodology for controlling the bottom-hole pressure during pipe connection in gas dominant wells. The methodology incorporates a dynamic model of the well fluid flow and the well-reservoir dynamic interaction. Available control actions during the drilling process are the gas injection rate prior to the pipe connection and choke valve settings during the pipe connection. Measurement of the pump rates, pump pressures, choke pressure and the bottomhole pressure are also available to support the control actions. However, during pipe connections and in the event of transient signal failures, the bottomhole pressure measurements will be suppressed.

The control methodology used is based on a non-linear model predictive control system, which predicts the near-future behavior of the well, and uses these predictions to obtain the optimal choke settings and pump rates. The model parameters are calibrated using measurements from the well, to ensure that the model is suitable for the predictions.

A field based case with gas injection has been examined using this control methodology. The results indicate that model based control can be utilized in developing an automated and integrated pump rate and choke control system for underbalanced drilling operations.
Underbalanced Drilling as a Tool for Optimized Drilling and Completion Contingency in Fractured Carbonate Reservoirs
Authors: Abdollahi J. , Carlsen I. M. , Mjaaland S. , Skalle P. , Rafiei A. , Zarei S.
Published: December 2007

Maintained pressure management and fracture network mapping are key issues for successful well construction in fractured carbonate reservoirs. Prediction and characterization of the fracture network prior to drilling is very difficult and challenge optimized well direction and placement in respect to the fractures. Avoiding productivity impairment by loss of drilling fluids is another major challenge.

Later stimulation of a micro-fractured reservoir invaded by drilling mud is extremely difficult or even impossible. Open hole completion is generally preferred in these type of reservoirs. Underbalanced drilling (UBD) is therefore an interesting option for enhanced data acquisition, avoiding reservoir impairment and achieving completion contingency for optimized well production and added value.

Locating and characterizing the natural fractures while drilling is a vital issue for appropriate well placement and selection of completion options during the field development strategy. Depending on the opening and extension of the fractures, the mud loss rates and volumes can differ from low to heavy. The associated fracture network is the main parameter contributing to well production.

Underbalanced drilling is one of the main recommended technologies for further development of fractured carbonate reservoirs in South-West Iran. Flow drilling, allowing the hydrocarbons to flow to surface while drilling, will be advantageous. With sufficient reservoir pressure, this method enables better fracture characterization and a dynamic decision process can be applied for drilling horizontal wells with optimized well trajectory intersecting more fractures. Formation damage can be avoided and dramatically reduce unsuccessfully drilled wells.
Technical Feasibility and Applicability of a Concentric Jet Pump in Underbalanced Drilling
Authors: Suryanarayana P. V. , Hasan ABM Khalid , Hughes W. James
Published: December 2007

We examine in this paper the feasibility of using a concentric jet pump to create an underbalanced condition while drilling subnormally pressured reservoirs, using only single phase injected fluids, eliminating the need for gas. A complete technical basis for the performance and design of jet pumps for underbalanced drilling applications is presented. The problem is handled in four parts: reservoir to jet pump suction, the jet pump itself, annular flow from jet pump exit to surface, and power fluid flow. Multiphase flow theory, viscous flow theory and jet pump flow theory are used to analyze the problem. The design goal is to find the correct combination of jet pump location, geometry, power fluid density and rate such that the jet pump exit energy is adequate to lift the mixed fluids and solids to surface. Other design considerations such as tolerance of varying reservoir conditions and depth, cavitation, sonic velocity limitations, and power fluid injection pressure constraints, are also taken into account in the design procedure. Jet pump design envelopes unique to its application in underbalanced drilling are developed to aid selection and design of the pump. A design program that implements the procedure has been developed. The procedure is illustrated with two examples: an oil well and a gas well. We find that the jet pump can successfully create an underbalanced state for a wide range of conditions. In general, for reservoir pressures in the range of 4 to 7 ppg equivalent, the jet pump appears to enable creation of an underbalanced condition without requiring injected gas, regardless of whether the reservoir is oil bearing or gas bearing. Operational and practical considerations that need to be addressed in proving the design are also discussed. Based on this work, we conclude that the concentric jet pump is a unique device technically suitable for a wide range of uncerbalanced drilling applications.
Practical Use of a Multiphase Flow Simulator for Underbalanced Drilling Applications Design – The Tricks of the Trade
Authors: Mykytiw C. , Suryanarayana P. V. , Brand P. R.
Published: December 2007

This paper focuses on practical use of a multiphase flow model for design of underbalanced drilling (UBD) applications. Since most UBD operations involve multiphase flows, UBD operations are synonymous with multiphase flow modeling. Once a candidate well has passed requisite reservoir valuation and screening criteria, the next step is to establish the technical feasibility of the technology and determine the key operational parameters including equipment specifications. Multiphase flow modeling is an essential part of this process, and as will be detailed in the paper, influences all aspects of design and construction of an UBD well.

By definition, the goal in underbalanced drilling is to maintain a pressure below pore pressure along the entire open hole section that is targeted for UBD. While a drawdown is indeed desirable, there is clearly an upper boundary dictated by wellbore stability and/or coning of undesirable phases. The UBD operational envelope is further bound by adequate hole cleaning performance through proper design of the circulation parameters. The conditions that satisfy these underbalanced parameters should also consider limitations of the bottom hole assembly (BHA) components, in particular motors/MWD, and realistic in regards to the injection criteria (rates and pressures). Finally, multiphase flow modeling over a range of conditions, including sensitivities and safety factors, allows the sizing of the surface equipment (with maximum reservoir inflow considerations), and thus implicitly influences the design of the entire UBD operation.

The primary purpose of this paper is to describe the strategy of effective multiphase modeling for UBD including modeling sequence and necessary sensitivities, to ultimately deliver a "robust" design. Reservoir uncertainty is the primary culprite to flow modeling flaws. Moreover, due to the relatively simplistic user interfaces on complex multiphase flow engine software, the results of the model may be misinterpreted. It is through an accepted modeling strategy that this risk is manageable. Although the design example employs a single commercially available simulator, Wellfo 7, the interpretation principles could be adopted with any "acceptable" industry model.
The Challenges of Numerical Simulation of a Complex Fractured Carbonate Reservoir with Available Disparate Data Sets
Authors: Iwere F. O. , Apaydin O. G. , Moreno J. E. , Nogaret C.
Published: December 2007

This paper presents the challenges of constructing adequate static and flow models of a field from disparate data sets, and the workflow methodologies adopted for integrating, reconciling, and extrapolating available data from multiple disciplines. This study uses a data set of about 300 wells penetrating a 2500-meter thick section of fractured and vuggy carbonates. A 30-year production history was used to calibrate the model; the main recovery mechanism of the complex is rock and fluid expansion, combined with a weak aquifer.

A reservoir simulation study was constructed to investigate the field behavior under natural depletion, water injection and gas injection, and to provide technical foundation supporting investments in future development projects. The static model comprises of a three-dimensional structural model, a matrix property model, and a fracture property model. There was no 3-D seismic. The complex system of normal and reverse faults dividing the structure into 70 fault blocks was created from well picks. The matrix property model was derived from limited routine and special cores, and vug analysis. The fracture property model was obtained by integrating fracture indicator logs, including DSI, image logs, conventional logs of different vintages, with fault orientation from structural conditioning, core analysis, PTA, well production and static pressure histories.

The complex structure, long production history and the various recovery mechanisms posed additional challenges in constructing and calibrating the flow models to historical performances. The fluid properties for the thick reservoir sections were derived using limited available fluid samples, and verified by history matching reservoir pressure and gas-oil ratio, which declined over time until secondary gas cap encroachment. The different vintage and accuracies of the pressure and rate measurement devices were also considered in evaluating the history match quality.
A Simultaneous Water and Gas Flood Design with Extraordinary Vertical Gas Sweep
Authors: Stone Herbert L.
Published: December 2007

Proposal

This paper describes a new secondary oil recovery method that will make the world’s producible petroleum reserves last decades longer. It makes water and WAG pattern floods passé. Its novel element is a unique completion configuration for simultaneous water and gas injection in a pattern flood. The gas is injected through one site located near the bottom of the formation, and the water is injected through a second separate site located directly above the first. High-rate water injection in the upper part of the formation greatly impedes the vertical upward flow of gas, causing it to finger horizontally far into the reservoir before flowing upwards. This mode of simultaneous injection can give a 3-4-fold greater vertical gas sweep of the formation than does WAG, the alternate injection of water and gas into a single completion interval. Such a flood can be initiated at any time in the life of a field, including after complete depletion.

When combined with the use of horizontal wells, the new approach is effective even in thin reservoirs. Also, calculations for a Prudhoe Bay-similar reservoir indicate that an additional recovery of 5 million barrels of oil above WAG recovery can be recovered from each 80-acre pattern, using the existing vertical wells

Injecting gas along with water gives higher oil recovery than water flood alone, because the presence of residual gas saturation at the end of a flood results in lower residual oil saturation than would result from a water-only flood. If the gas miscibly displaces the oil, the water-gas residual oil will approach zero. Even for gases that are completely immiscible with the oil, a number of investigators have found the residual oil after a water-gas flood to be in the range of 0-50 % of the water flood residual, in water-wet and intermediate-wet reservoirs. These studies lead to the conclusion that both miscible and immiscible gases are effective in lowering the residual oil in a water-gas flood. However, there will likely be many reservoirs for which the cost or lack of availability of the miscible fluid will make immiscible gases more economic than miscible ones.

An approximate quasi-steady state reservoir simulator was developed and used to identify this superior mode of gas and water injection. Transient simulation could not be used for this purpose because of the numerical dispersion (truncation error) inherent in it. The quasi-steady state simulator is validated by a favorable comparison of its solution to one resulting from a finely gridded transient reservoir simulation. The two methods yielded very nearly the same quasi-steady state shape and size of the gas-flooded zone. The gas saturations in constant saturation zones established by the flood were also matched.
Variation of Fracture Opening with Pressure -- Key to Well Productivity in Naturally Fractured Reservoirs
Authors: Du Y. , Guan L.
Published: December 2007

Naturally fractured reservoirs usually developed many scales of fractures, for example, the super-high-permeability flow in big fractures, mid-permeability flow in small fractures and very-low-permeability flow in matrix rock. This results in the subsurface multi-scale flow during the reservoir development. This multi-scale flow makes it tougher to analyze the well productivity than that of a conventional reservoir. In this paper, muti-rate well-testing data were used to calculate the production capacity at different reservoir pressures in naturally fractured reservoirs. The method is exemplified with two wells in a case reservoir. The calculation results are very similar to field production data. We conclude that oil production rate in these kind of reservoirs is not only impacted by both two-phase flow and non-Darcy flow as in conventional reservoirs, but also impacted by the variations of fracture opening. This conclusion can be used to better define the optimal rate for the reservoir under different reservoir pressures, thus further improve our forecast accuracy and overall field development results.
Simulation Investigation of Casing Eccentricity Estimation for Different Inclination Angles and Tensile Forces Using Finite Element Method
Authors: Akgun Ferda , Al-Ghadban Hamed H.
Published: December 2007

Casing eccentricity has been considered as a problem during design and calculations of primary cementing, particularly in inclined and horizontal wellbores. Engineering calculations are usually based on the assumption of concentric annuls, which usually leads to erroneous or at least inaccurate results. One of the major problems of primary cementing is improper displacement of cement slurry around casing in the annular space. This often leads to gas channeling I gas wells, which consequently necessitates expensive squeeze job. Therefore, it is important for accurate engineering designs to use actual eccentricity values and not a concentric casing assumption in the derivations and application of used equations. This requires accurate eccentricity estimation.

The ambitious objectives of this study are to estimate the casing eccentricity at inclined section of a directional well as a function of hole inclination angle, applied tension, and measured depth. To achieve these goals, a two-dimensional finite element method (FEM) was used. Furthermore, the influences of inclination angle, casing length, and tension force on the calculated values of casing eccentricity are investigated. Casing lengths of 102, 204, and 300 ft from the bottom of the hole with different inclination angles of 15°, 30°, 45°, 60°, 70°, and 90° were modeled under different tensile forces i.e., 0, 20000, 40000, and 60000 lbf., respectively.

The results indicate that increase of inclination angle increases the casing eccentricity. The inclination angle has a major effect on the casing eccentricity when it is between 0° (vertical hole) and 30° (inclined), and change in effect when it is between 45° (inclined) and 90°(horizontal).

The results also showed that as the applied tension force increases, the casing eccentricity decreases. Furthermore, it is concluded that the casing length has no effect on the calculated values of casing eccentricity.

The attained results of this study provide more understanding of the role of casing eccentricity with respect to hole inclination and tensile force. Furthermore, it may have a real impact on well borehole cleaning, casing design, and cementing hydraulics of inclined/horizontal wellbore holes.
Meeting the Challenges in Design and Execution of Two High Rate Acid Gas Injection Wells
Authors: Benge Glen , Dew E. G.
Published: December 2007

Two high rate acid gas injection wells were drilled in the LaBarge area of Wyoming. These wells were designed for injection of up to 65 million scf/day of a mixture of 65% H2S and 35% CO2. The primary engineering challenges in well design, casing selection, and cementing of the injection strings, along with the related operational challenges for both wells are discussed. Key drivers influencing zonal isolation, salt zone loading, casing and centralizer selection are presented.

Casing selection was influenced by corrosive gas composition, high injection rates, and the potential for salt zone loading. The use of CRA tubulars, heavy wall casing for the salt loading, handling requirements, and centralizer selection are discussed.

The primary driver in cement design was resistance to CO2, as past work has shown little H2S interaction with cement under these well conditions. A discussion of the development of a high alumina cement system with low fluid loss to address CO2 resistance and long liner length is coupled with the quality control steps taken from time of manufacture of the specialty cement to final placement in the well.

Also described is the development of an alternate Portland cement system containing a reduced concentration of Portland cement by the use of sized particles to dilute the cement and reduce total system permeability.

The unique engineering solutions resulted in operational challenges with casing running, cementing materials and equipment. A description of the location problems and the steps taken to resolve the issues are included.
3-D Elastoplastic FEM Modelling in a Reservoir Simulator
Authors: Han G. , Stone T. , Liu Q. , Cook J. , Papanastasiou P.
Published: December 2007

With an increase of loading forces due to continuous reservoir depletion, irreversible rock displacements occur, leading to various problems such as reservoir compaction, surface subsidence, formation fracturing, etc. In the oil industry, numerous efforts have been made to incorporate rock elastoplastic analyses into widely available reservoir simulators. Based on current rock mechanics theories and experimental results, a 3-D elastoplastic approach solved with the Finite Element Method in Corner Point Geometry grid cells is proposed, and its application to a commercial reservoir simulator is demonstrated.

Both Mohr-Coulomb and Drucker-Prager yield criteria are used as definitions of yield surface, where rock behaves elastoplastically. The plasticity modulus is expressed as a function of both rock stresses and strains. Using a generalized plastic strain variable, two types of work-hardening rules including a hyperbolic law and a power law are applied to describe rock cohesion-hardening behaviour, correlated with mechanical behaviour of a medium to strong reservoir sandstone. Simulation results reveal their relative advantages and suggestions are provided for future simulator development.

This discussion can serve as a basis for development of more comprehensive and efficient geomechanical models for large-scale reservoir simulation.
Experimental Investigation and Numerical Simulation of Water Imbibition in Fractured Turbidite Systems
Authors: Cunha L. B. , Bonet E. J. , Cunha J. C.
Published: December 2007

The flow description applied for double porosity reservoirs is of paramount importance for evaluating the performance of fractured turbidite reservoirs. Many authors have measured in the lab and formulated formulas describing the transfer function between the fracture and the contiguous less permeable porous media. Other authors using these transfer functions described the flow behavior in a system of double porosity and double permeability.

In this work, laboratory tests were performed in long cores with different fluids, diverse wettability condition and various flow rates. At first experiments were conducted on unfractured cores. Then, for the same core, geometry, flow pattern and fluids, the transfer function that occurred in a subsequent flow test for a double porosity system was measured. The saturation history during the test was measured with an X-ray scanning system. The experiments were conducted quite differently from those commonly used in imbibition experiments and provided additional insight into oil recovery from fractured reservoirs.

In order to describe the lab flow tests it was used three mathematical approaches, namely: a finite difference commercial reservoir simulator, a semi-analytical solution, and an analytical solution for the hyperbolic system of equations governing the process. The experimental results obtained were matched satisfactorily by the three mathematical approaches investigated. At the end, the first two mathematical methods were applied to predict the production behavior for an equivalent injection pattern in a Brazilian fractured turbidite reservoir.
Improvements for Flow Correlations for Gas Wells Experiencing Liquid Loading
Authors: Kumar N.
Published: December 2007

Improvements to pressure traverse (predictions) using simple modifications to a two phase flow program (Gray1,2 correlation) for gas wells producing some liquids have been discussed in this paper. The Gray correlation was found to be the best of several initially tested. Improvements in pressure traverse predictions with modifications are shown compared to a set of high quality data. The absolute average error between the measured data and calculated data for fifteen wells was reduced from about 28 % to about 22% using suggested modifications or improvements. Modifications tested included modeling downhole condensation or vaporization of water, a correction for water density, use of a regression technique to minimize error in a program that was written to allow input constants to help adjust predications to measurements, and adding multiphase flow regimes in the two phase flow program. Also, some suggestions for future work to improve correlations for liquid loaded gas well pressure profile predications are discussed.
Integrated Characterization of Low Permeability, Submarine Fan Reservoirs for Waterflood Implementation, Chicontepec Fan System, Mexico
Authors: Tyler Noel , Gachuz-Muro Heron , Rivera-R. Jesus , Rodriguez Dominguez Juan Manual , Rivas-Gomez Santiago , Tyler Roger , Nunez-Vegas Victor
Published: December 2007

Through integrated characterization of highly heterogeneous submarine fan reservoirs of the Chicontepec fan system optimum location for a waterflood pilot was identified and tested. Positioned in a high quality, comparatively low heterogeneity part of the complex, results of the pilot indicate that water flooding the Chicontepec is feasible and that the reservoirs tested would benefit from a several pattern, long-term water injection program.
Methodology to Implement the Optimum Fracture Design in an Oil-Bearing Reservoir
Authors: Stegent N. A. , Sorenson F. , Brake S. C. , Fontana C. J.
Published: December 2007

Preparing a completion design can require time and effort to optimize economic returns. Often, actual production results do not reflect the predicted outcome. Many reasons can account for this discrepancy, ranging from incorrect interpretation of petrophysical analysis to unintentional deviation of design during job execution at the wellsite. Completion analysis is essential for determining why actual and predicted outcomes vary; it also helps determine where inaccurate values entered into the design process.

This paper discusses the methodology used to execute an optimized production design. Wellsite analysis and post-production analysis are essential to this process. The paper describes processes used to obtain data for these analyses and for several other methods used to verify prejob parameters. Onsite fluid tests must be comparable to prejob tests to ensure that fracturing fluids perform in the reservoir as in the laboratory. Well selection, petrophysical and rock mechanics analysis, and design considerations are detailed. Most importantly, the onsite mini-frac analysis intrepetation is the iterative link to verify design parameters and is used to incorporate changes that will achieve the optimum stimulation treatment.
Reservoir Performance Under Solution Gas - Drive and Gravity Drainage
Authors: Padilla-S. Roberto , Camacho-V. Rodolfo
Published: December 2007

This work examines the well and reservoir performance under both solution gas-drive and gravity drainage in homogeneous systems. Based on synthetic information obtained with a fully implicit black-oil simulator, the influence of different parameters like oil rate, position of the producing interval, wellbore pressure level, skin factor, and vertical permeability, for both constant oil rate and constant pressure production modes are documented. Analytical results for the reservoir performance during the boundary dominated flow period are derived. An approximate expression that describes the variation of oil saturation with average pressure is presented. For constant oil rate production, the influence of gravity drainage on the inflow performance relationships curves is studied, and a new correlation is presented. For constant pressure production, the decline curve behavior is analyzed and it is found that under favourable gravitational effects, the production behavior shows two decline stages such as double porosity systems; however, it does not follows the typical decline type curves for naturally fractured reservoirs. At certain backpressure values during the first stage an exponential decline behavior could be observed, while during the second stage values of the decline exponent less than zero are observed.
Experimental Study of Effective Diffusion in Porous Media
Authors: Islas-Juárez R. , Samaniego V. F. , Luna E. , Perez-Rosales C. , Cruz J.
Published: December 2007

In this work the effective molecular diffusion in homogeneous porous media was studied. An experimental setup was constructed to measure the effective molecular diffusion coefficient in packed unconsolidated sands, which allowed to take samples of fluids at different positions and times. The fluid samples were analyzed by gas chromatography to determine fluid concentration; these data were analyzed using the Fick’s second law to calculate the molecular diffusion coefficient. These results were compared with those obtained using a different methodology based in pressure changes developed by Luna et al. A good agreement between both methodologies was obtained.
Application of Interval Pressure Transient Testing with Downhole Fluid Analysis for Characterising Permeability Distributions, In-Situ Flow Fractions and Water Cut
Authors: Jackson R. R. , Xian C. , Carnegie A. , Gauthier P. , Brooks A. D.
Published: December 2007

In this paper we describe the application of interval pressure transient testing (IPTT) combined with downhole fluid identification and analysis (DFA) for characterising horizontal and vertical permeability, and determining in-situ effective oil mobility and downhole water cut in a complex and heterogeneous carbonate reservoir. We provide three well examples where interval transient testing and fluid sampling was applied at multiple depths, and resulted in an improved understanding of a complex reservoir.
Use of Advanced Completion Solutions to Maximise Reservoir Potential – Experiences in The Snorre Field
Authors: Skarsholt Line T. , Mitchell Anthony F. , Bjørnsgaard Are H.
Published: December 2007

The Snorre licence operating in blocks 34/4 and 34/7 of the Norwegian North Sea was the first to install surface operated zonal control to allow selective production from different sections of the reservoir. The concept of Downhole Instrumentation and Control Systems (DIACS) has, subsequently, been further developed and refined and is used today, by many operators. The Snorre field remains at the forefront of this development and the technology has been employed in a further 17 wells (both injectors and producers) across the field.

The Snorre reservoir is highly heterogeneous and faulted and consists of layers with differential pressures of up to 150 bar. This has lead to many instances of rapid water and gas breakthrough in individual zones, whilst other layers have remained largely un-drained. The use of DIACS has lead to improved reservoir exploitation and has formed the basis for implementation of the concept as the preferred completion solution for the northern area of the field, via the Snorre B platform.

This paper will focus on the use and advantages of advanced completions from both a reservoir and production engineering viewpoint; it will summarise experience gained with regard to mechanical aspects of the completion hardware; data collection and management and will discuss future plans and expected benefits of this type of completion system.
Pressured Mud Cap Drilling from A Semi-Submersible Drilling Rig
Authors: Terwogt J. H. , Mäkiaho L. B. , van Beelen N. , Gedge B. J. , Jenkins J.
Published: December 2007

Pressured Mud Cap Drilling (PMCD) is an advanced technique to control wells which encounter heavy mud losses and has been applied on onshore and offshore wells with surface wellheads. The key to successfully apply the technique is the use of a Rotating Control Device (RCD), which is a technology taken from Under Balanced Drilling (UBD). PMCD has not been applied to date on subsea wells as rigging up the RCD on the drilling riser brings additional challenges compared to surface wells.

Three subsea wells were drilled Offshore Sarawak, utilizing the PMCD technique. A detailed review was made to rig up an RCD on the drilling riser of a Semi-Submersible drilling rig. The riser between the subsea BOP and the RCD at surface formed a low-pressure system to control the well.

The first 2 wells did not see any losses but on the 3rd well, total losses occurred and the system was activated. The final result gave reason to look back on a successful operation but also good learnings were made for future operations.
High-Temperature Plug Formation with Silicates
Authors: Bauer S. , Gronewald P. , Hamilton J. , LaPlant D. , Mansure A.
Published: December 2007

A grouting system is being developed that is applicable to water shutoff, steam flooding, and high-temperature grouting/plugging for lost circulation. This grouting system uses silicate hydrates as the plugging material. We describe a means to introduce sodium silicate and an activator through a single tubular by encapsulating the activator in a material that is temperature sensitive, thus delaying the initiation of the reaction. The formation of silicate hydrate plugs has been studied over the range of 80°C to 300°C as well as the chemical stability of silicate hydrate for 10-12 weeks.
Deployment of Swelling Elastomer Packers in Shell E&P
Authors: Kleverlaan Martijn , van Noort Roger. H. , Jones Ian
Published: December 2007

In Shell Exploration & Production, swelling elastomers have been deployed in a variety of applications: as a means to establish zonal isolation in liner completions, as a production separation packer, and as an integral part of an expandable open hole clad. In these applications, the elastomers have been run in various open hole, casing, and tubing sizes. A total of around 60 deployments in Shell have been recorded, all of which were technically successful.

Case examples of each of the three mentioned applications will be presented from Shell operations in the North Sea, the Middle East, and the Far East.
Asphaltene Deposition During Drilling with Emulsified Drilling Fluids
Authors: Fjelde I.
Published: December 2007

If the reservoir oil and drilling mud filtrate of drilling fluids are not compatible, mixing of these fluids in the oil reservoir can cause formation damages. For environmental reasons base oils with low aromatic content are preferred in emulsified drilling fluids. The potential for asphaltene deposition by mixing of emulsified drilling fluids and reservoir oils has been studied using stock tank oils with low and high asphaltene content. Two low aromatic emulsified drilling fluids were used, one with mineral base oil and one with synthetic base oil. Asphaltene deposition was studied both in bulk experiments and in floods using core-plugs of sandstone outcrop of low-to-medium permeability.

When crude oils and mud filtrates were mixed in bulk, asphaltene deposition was detected in all cases. The formation damage was largest when the mud filtrates were mixed with the crude oil with the highest asphaltene content. During backflooding with the same crude oil, the formation damages caused by asphaltene deposition were removed. It is concluded that the potential for formation damage by asphaltene deposition is highest for reservoir oils with high concentrations of asphaltene close to the onset of asphaltene deposition. The potential will increase with decreasing aromatic content in the emulsified drilling fluids. If the reservoir oil is not saturated with asphaltenes and the damage area can be swept by the reservoir oil, formation damages caused by asphaltene deposition can be nonpermanent. If white oil is used in laboratory experiments, the potential for asphaltene deposition and removal of this damage can come out wrong.
Cased-Hole Reservoir Saturation Monitoring in Mixed-Salinity Environments – A New Integrated Approach
Authors: Ma S. M. , Al-Hajari A. A. , Berberian G. , Ramamoorthy R.
Published: December 2007

For mature-reservoir description, accurately monitoring oil saturation is a major challenge. Traditional methods for cased-hole saturation monitoring use either pulse-neutron capture or spectroscopic nuclear logging tools. This paper presents a new approach to cased-hole resistivity measurements. This approach has an advantage over nuclear logs because its depth of investigation is more than 10 times that of any nuclear logging measurement.

Calculation of saturation from resistivity logs is difficult if formation-water salinity is mixed. In this paper, we overcome this difficulty by combining pseudo formation-water salinity from carbon-oxygen (C-O) logs with bottomhole samples. Using this calibrated formation-water salinity and variable Archie saturation exponents of drainage and imbibition, calculation of reservoir saturation from cased-hole resistivity measurements becomes more accurate.

Reservoir saturation is also calculated from C-O logs run at the same time as cased-hole resistivity logs. Wellbore fluid reinvasion is identified from C-O derived saturation across perforation intervals. In unperforated intervals, saturation derived from C-O compares favorably with the original openhole log analysis, well history, and fluid-flow profiles from production logs. Reservoir saturation is finalized by integrating saturations from cased-hole resistivity and C-O measurements. This paper illustrates the importance of integrating all data to obtain accurate saturation calculation of producing reservoirs in mixed-salinity environments.
Operational Experience with Use of a Hex Pump on a Land Rig
Authors: Kverneland Hege , Kyllingstad Åge , Moe Magne M.
Published: December 2007

This paper focuses on the operational experience that was gained during field test of the Hex Pump on a land rig in Jasper, Texas in October 2003. This field test showed that the pulsation frequency in the flow from the Hex Pump did not interfere with the MWD-measurements, providing a much cleaner signal to the directional driller. Also, the overall power consumption on the rig was reduced due to use of AC-motors.
Drilling Time Reduction Through an Integrated Rock Mechanics Analysis
Authors: Nes O.-M. , Fjær E. , Tronvoll J. , Kristiansen T. G. , Horsrud P.
Published: December 2007

A working methodology to minimize wellbore stability problems has been established through the use of unique laboratory tests, an experimental database for fluid-rock interaction and physical properties of shales, and an integrated modeling approach utilizing different types of experimental and field data. The model simulations provide output accounting for a wide range of input parameters such as well inclination, mud chemistry, rock mechanical properties, field stresses and pressures, formation anisotropy and shale mineralogy. The model output can subsequently be used to diagnose field drilling problems or to design drilling operations. As an example, data from an HP/HT field offshore Mid-Norway as well as a field in the overpressured shales in the southern part of the Norwegian North Sea have been analyzed and compared.