bluuebunny/crossref_metadata_2025 huggingface dataset:
Capturing and Preserving Sandbody Connectivity for Reservoir Simulation: Insights from Studies in the Dacion Field, Eastern Venezuela
Authors: Frorup M. , Jenkins C. , McGuckin J. , Meredith J. , Suellentrop G.
Published: December 2007

A critical part of the redevelopment plan for Dacion Field is to optimize depletion of the middle sands. To help develop a strategy for this, four geological models were built, upscaled, and numerically simulated. The models were constructed for the L2U-M2 and the P1-R0 intervals in both East Dacion and West Dacion.

The deterministic framework for each geological model was built using a 3D seismic survey and wireline log correlations. Several techniques were used to distribute model properties including object modeling for facies bodies, sequential Gaussian simulation for porosity, a poroperm cross-plot for permeability and height vs. saturation curves for water saturations.

Multiple realizations were generated for each of the four models and streamline modeling was used to identify key realizations with differing amounts of heterogeneity. These were then scaled-up and numerically simulated. The realization achieving the closest match to overall reservoir performance was chosen for detailed well history matching.

The detailed history matches were optimized by modifying permeability/transmissibility values and relative permeability curves. Subsequent forecast runs identified 54 new well locations and showed that incremental recoveries of 6 to 18 percent of OOIP are possible through a combination of infill drilling, water injection, and the commingling of production.

The simulations proved very useful for developing strategies to optimize production, but recent drilling indicates that the models were not very successful in predicting the performance of new wells on an individual well basis. The key reasons for this are (1) the distribution and connectivity of sand bodies in the models are different than those in the reservoirs, and (2) the data and analysis tools used in the modeling work need improvement.
Modeling Fracture Fluid Cleanup in Hydraulic Fractures
Authors: Balhoff Matthew , Miller Matthew J.
Published: December 2007

The retention of fracturing fluid in a proppant pack reduces the dimensionless fracture conductivity, Fcd, resulting in poor well productivity regardless of fluid type (gelled oil, crosslinked polymers, viscoelastic surfactants, or foams). Analytical expressions derived in this paper can be used to calculate the extent of fracture clean up, n* under a set of production conditions. Dimensionless parameters, β (reservoir: fracture mobility ratio), R (clean: fouled fracture permeability ratio), and τ0 (dimensionless fluid yield stress), which affect n* are identified in the model. A second fracture cleanup model is also proposed and is used to estimate the dimensionless parameter values.

Fluid removal is a balance between the differential pressure within the fracture facilitating cleanup and the fluid yield stress resisting cleanup. The driving force for fracture cleanup weakens as fluid is removed, until an equilibrium cleanup extent, n*, is reached. The equilibrium model predicts that n* increases greatly with decreasing dimensionless yield stress, τo. The magnitude of η* is also greater for high clean: fouled permeability ratios, R. η* is expected to increase with an increase in the reservoir: fracture mobility ratio, β, until an optimum is reached and then decrease with increasing β. The critical process of parameter estimation is achieved by making experimental measurements and by history matching published fracture flowback data using the transient model.

Practical application of this work is aimed at identifying pathways to improved well performance. For example, data from the Codell formation showed that η* was 45%. Parameter values of 0.92, 2.0, and 5.0 for τo, β, and R, respectively were found to fit the transient flowback data. If these parameters are accurate, η*, can be increased to 95% (doubling the expected production revenue) if a fluid with τo of 0.1 is used and all other parameters remain the same.
A Multiphase Model For Evaluation of Filtration During Drilling and Fracturing of Wells
Authors: Civan Faruk
Published: December 2007

The majority of the previous models have neglected the effect of the presence of multi-phase fluids in the near-wellbore formation during drilling and hydraulic fracturing. Consequently these studies have used single-phase filtration models leading to the analyses of experimental data with inherent errors. In this paper, a multi-phase fines migration and filtration model is developed and implemented for evaluation of the measures taken for filtration control associated with the completion and workover fluids. This model considers the transport of additives and fines, and their interactions with the filter cake and reservoir formation. The effects of the alteration of the permeability and porosity of the formation and cake matrix, petrophysical flow functions, including wettability, end-point saturations, relative permeability, and capillary pressure, as well as the characteristic parameters of the filtration fluids containing fines, such as non-Newtonian fluid behavior of the slurries and gels, are therefore included.
The Modeling of the Effect of Water Blockage and Geomechanics in Waterfracs
Authors: Settari A. , Sullivan R. B. , Bachman R. C.
Published: December 2007

This paper describes the study of the effect of the water blockage for a well in the Bossier play in Texas. The history of the well was modeled with a coupled reservoir and fracture model, which accounts both for the dynamic fracture propagation during the job and the static fracture during production. The model was constrained by the interpreted microseismic data, 2-phase cleanup, production and buildup data, thus reducing the uncertainty in the interpretation. The results show convincingly strong geomechanical permeability effects, which can be deduced from clean-up data. Water blockage alone has a small effect on well productivity, but formation damage can have a noticeable effect. In addition, the use of PTA to identify the various features was also investigated.
Development and Application of Improved Reservoir Characterization for Optimizing Screenless Fracturing in the Gas Condensate Jauf Reservoir, Saudi Arabia
Authors: Al-Qahtani Mohammed Y. , Zillur Rahim , Biterge Mustafa , Al-Adani Nabeel , Safdar Muhammad , Ramsey Lee
Published: December 2007

Efficient field development requires excellent quality reservoir and field data to be used in the reservoir and production models. Hence, improved reservoir characterization is very important for obtaining optimal gas recovery. This paper presents the results of development of improved reservoir characterization and sand prediction models leading to successful hydraulic fracturing treatments. These models were applied in the Jauf sandstone reservoir in the Ghawar Field, Saudi Arabia.

Two aspects were thoroughly investigated and improved upon in the process of our study. First, fracturing technique using the best possible combination of fluid, proppant, and perforation interval was developed that covers most of the vertical layers and creates deep conductive lateral penetration. Second, screenless completing technique was developed to minimize sand production. Correct proppant type and size, chemical agent, and choice, extent, and placement of perforation type and interval were developed to optimize this process. Solution to sand production problem was developed because of the Jauf sandstone reservoir quality, which has a high tendency to produce sand against moderate to strong drawdown pressures. A new sanding model was also built to assist in the completion strategy. This model differentiates between layers that have strong sanding tendency and layers that are competent. Finally, sand-free production rate was reached and maintained by evaluating post-fracture performance.

In order to optimize the completions in the Jauf reservoir, development of a comprehensive data set was required. Improved petrophysical and mechanical properties models, using cores, logs, geological and geophysical properties, and field performance, were developed. Calibration of the models using up-to-date field responses where possible was performed. Production forecasts were generated from the data set to characterize well quality. Utilizing this comprehensive data set with the new completion model developed to address the issues of gas optimization and sand production led to successful optimized screenless completion techniques. Detailed description of pre-fracture data preparation and post-fracture data analysis are presented in this paper.

Development of improved reservoir characterization model has shown that quality data leads to quality engineering and successful well completion optimization.

Introduction

In order to optimize the completions in the Jauf reservoir, a comprehensive data set was required to develop an improved petrophysical and mechanical properties model. Calibration of the models was done with core and production data where possible. In addition sanding was a problem associated with gas production in the Jauf. A new sanding model was built to assist in the completion strategy to reduce sanding potential/production.
Reaching Deep Reservoir Targets Using Solid Expandable Tubulars
Authors: Gusevik Rune , Merritt Randy
Published: December 2007

For years operators have been forced to set drilling liners prematurely due to downhole conditions such as lost circulation and abnormally pressured formations. The conventional solutions for running unplanned casing strings have prevented some operators from reaching the well's projected target with sufficient casing inside diameter (ID). Not only has this conventional solution been a hindrance to maintaining sufficient IDs, it has proved unsuccessful when aiming for certain ultra-deep reservoir targets. Reduced hole size may lead to an inaccurate evaluation of the reservoir or prevent the reservoir from being produced efficiently.

Solid expandable tubulars add flexibility and versatility to operators' casing programs when encountering abnormal downhole restraints and obstacles. Additional casing strings can be proactively incorporated into the well program making the odds of reaching the target more realistic. With recent technological advancements, solid expandable tubulars are providing the added benefit of obtaining the optimum available casing ID when a drilling liner is needed.

The expanded liner ID, approximately 10 to 20% above conventional liners, can put drilling programs back on track in a cost-effective manner. Solid expandable tubulars can and have been the difference between sidetracking or plugging the well altogether. Having a solid expandable tubular contingency string on standby gives an operator the added option of pushing a given hole section even further than planned when pursuing deep reservoirs.

This paper discusses how using solid expandable tubulars improve an operator's ability to reach a proposed well target successfully. Insight into the industry's growing acceptance of using solid expandable tubulars in the initial engineering of a well is included, along with the economical benefits of using this technology not only as a contingency casing string but also as a primary casing string.
Extending the Frontiers of Solid Expandable Tubular Technology (SET): The Challenges - A Review of Installations in the Niger Delta
Authors: Owoeye Oladele O. , Nwabueze Chris , Odita Charles , Uzoho Foster , Adegborioye Adetola , Erivwo Ochuko , Oluwajuyigbe Olugbenga , Cook Lance , Bullock Michael , Arredondo Eduardo
Published: December 2007

With the vision to improve production in SPDC by 20% (to over l.OMMbopd) in the short term coupled with incessant community disturbance & the thrust to reduce environmental impact, most new wells favour utilising existing facilities and innovative technology to reduce cost & boost production. Expandable Tubular Technology (ETT) was one the key technologies identified for to achieve this. Over 150 wells were identified for this technology in the medium term with 3 wells selected as quick wins for deployment of the SET in 2001. The selection criteria were based on low risk, reduced unit technical cost and the need to extend the envelope of the technology.

This paper focuses on the challenges encountered in the planning & execution phase. It addresses the contracting, procurement and logistics constraints associated with the first deployment of the technology outside the Gulf of Mexico. It emphasises the engineering considerations applied to assess the technical feasibility of deploying SET. The applications also utilised a novel cementing technique "Settable Spotting Fluid" from Halliburton to minimise the risk of cross flow & low side channelling, a common situation in high angle applications in the Niger Delta. Finally, It reviews the economic justifications and highlights the value of the technology (accelerated production, reduced risk cost & lost opportunity).

The challenges encountered and mitigated during execution climaxed with the installation of the World's first horizontal Open Hole Liner (OHL) in Agbada 1ST. The successes have now extended the application of the technology from the current 20% of the global market to 80% of the global market (high-angle/horizontal wells) with a thrust of revolutionizing the concept of well delivery.
The Use of MRI Data for Predicting Well Performance and Aiding Reservoir Description: Hidalgo Co., Texas
Authors: Altunbay Mehmet , Ohnoutka Mark , Robinson Mike
Published: December 2007

Historically, wireline log data are used to determine net pay with formation resistivity being the best tool to find hydrocarbon-bearing zones. Merely identifying hydrocarbon zones in the wellbore is not always adequate in providing quantitative data needed to make economic completions. This is especially true when fracture stimulation is routinely applied. Estimation of producing rates, especially water production, is crucial in making the correct decision to complete and fracture stimulate a zone or to by pass the interval. A method has been developed using MRI data to predict gas and water rates through the use of synthetic capillary pressure curves. Using Purcell's permeability model and the Corey-Burdine equations, fractional flow curves can be developed for a complete section and prediction of water and gas rates may be made for individual zones, thus aiding the engineer in making economic completion recommendations.

The present work reveals a stepwise procedure of generating the estimation of producing rates for gas and water by using MRI and resistivity wireline data for completion practices. Further presented in this paper is the application of synthetic capillary pressure data to reservoir modeling and characterization. Rock typing and defining hydraulic flow units is a natural extension of predicting flow rates. Data from the MRI is used as a continuous synthetic core from which flow units have been related to rock types and their flow characteristics. Definition of these intervals has aided in the reservoir description and characterization of a newly developed fault block within the field. MRI derived data such as effective porosity; capillary pressure, relative permeability, and fractional flow behavior are being used in a model to predict gas water contacts, flow rates and recoverable gas reserves within the pilot study area. This knowledge will guide drilling location optimization within the fault block and ultimately within the field when additional verification is obtained in the neighboring wells.
Pore Pressure Control of Fracture Reactivation in the Ghawar Field, Saudi Arabia
Authors: Stenger B. A. , Ameen M. S. , Al-Qahtani Sa'ad , Pham T. R.
Published: December 2007

The Ghawar field is the largest oil field discovered in the world. It is located in the Eastern Province of Saudi Arabia. The Arab-D reservoir (Upper Jurassic) consists of high energy shallow marine carbonate sequences capped by evaporites, oolitic grainstones forming the upper part of the reservoir. From 1983 to 1990, the southern part of the Ghawar oil field (South Uthmaniyah, Hawiyah and Haradh) was mothballed due to a period of low oil demand at the international level. During this mothballing period, Saudi Aramco reservoir management team pursued its established policy of monitoring reservoir pressure and temperature.

Following a close review of these pressure data, a clear pressure drawdown was identified during the mothballing period in a few wells centered around a localized area of the Haradh production area (South Ghawar). After eliminating all possible man-made causes (e.g. production) the available data point to a geomechanical explanation of the observed pressure drawdown. Fracture re-opening and/or propagation possibly related to neotectonic activity during a period of pore pressure recovery – after an initial period of primary depletion – is the most plausible explanation. Fracture characterization and simulation indicate the existence of natural fractures. Recent seismic events recorded in and around the study area further support the proposed explanation. Implications of the proposed geomechanical link on the reservoir performance are discussed.
Lost Hills Field Trial – Incorporating New Technology for Reservoir Management
Authors: Brink J. L. , Patzek T. W. , Silin D. B. , Fielding E. J.
Published: December 2007

This paper will discuss how Chevron U.S.A. Inc., a ChevronTexaco Company (ChevronTexaco), is implementing a field trial that will use research developed software integrated with Supervisory Control and Data Acquisition (SCADA) on injection wells, in conjunction with satellite images to measure ground elevation changes, to perform realtime reservoir management in the Lost Hills Field. Implementation of a new software control model to restrict hydrofracture growth in water injection wells is being field tested.1 Synthetic Aperture Radar Interferograms (InSAR) are being obtained on an approximately 60-day interval to determine subsidence rates and will be used as an input variable for pattern voidage calculations. Incorporating new and innovative technologies is helping ChevronTexaco produce a very unique and challenging diatomite reservoir.
Reservoir Management Scope In A Mature Niger Delta Field
Authors: Ikomi J. G. , Nwosu C. J. , Mandhane J. M. , Akem B. T.
Published: December 2007

An integrated petroleum engineering investigation of the Awoba field X reservoir (about 300 feet thick) was necessitated by its puzzling production performance. Considered to be one of the largest hydrocarbon bearing reservoirs in the Awoba field, with an ultimate oil recovery of 52.5 MMstb, this reservoir produced only 13.7 MMstb dry oil and started cutting water. Results of a recent sidetrack from an existing well in the field have provided a basis for updating existing static and dynamic models which in turn have provided a framework for simulating the movement of water and consequently improved reservoir management.
Hydraulic Fracturing Case Histories in the Carbonate and Sandstone Reservoirs of Khuff and Pre-Khuff Formations, Ghawar Field, Saudi Arabia
Authors: Rahim Zillur , Bartko Kirk , Al-Qahtani Mohammed Y.
Published: December 2007

As part of gas production enhancement and quick recovery of reserves initiative, hydraulic fracturing campaign was initiated in 1998 to treat the sandstone and carbonate formations in the Ghawar gas fields in Saudi Arabia. To date, numerous wells have been matrix acidized, acid fractured, and proppant fractured. Many different procedures and fracturing techniques have been adopted as part of learning process to optimize candidate selection, perforation strategy, fracture design, and implementation.1,2 The incremental production from the Khuff carbonate gas ascertains the success of the acid fracturing treatments.3 For the Pre-Khuff sandstone reservoirs, because of the unconsolidated nature of some high potential sandstone layers, indirect fracturing technique has been adopted where the consolidated, low porosity section is perforated and from where the induced fracture is initiated.4 This procedure curtails the risk of sand production. Very recently, fracturing wells with frac&pack technique and completing them with mechanical screen are being implemented. Successes on these Pre-Khuff treatments are usually judged by sand free production rate and conditions and by comparing post-fracture production increase with simulated, pre-fracture production based on reservoir properties calibrated by post-fracture production match. In most cases this gain is significant to justify the expenses of the fracture treatment. However, the priority in Saudi Aramco is to recover the required volume of gas to feed its giant gas plants. This paper presents field cases from the carbonate and sandstone reservoirs treated with acid and proppant, respectively and provides a general picture of how all the fracture treatments are currently being conducted.
Case History: Internally Coated Completion Workstring Successes
Authors: Pourciau Robert D.
Published: December 2007

Completion workstrings must endure an extremely hostile environment of erosive and corrosive fluids. Today's improved internal plastic coatings can protect the significant investment in drill pipe from erosion/corrosion, as well as minimize completion trouble time caused by pipe debris (scale). An internally coated, Class 2 drill string was used for 2!/2 years to successfully Frac Pack seventeen, high productivity, Gulf of Mexico Deepwater completions in the Genesis Field. More than 2,000,000 pounds of abrasive proppant was pumped without a pipe failure.
Analysis of Well Test Data From Permanent Downhole Gauges by Deconvolution
Authors: von Schroeter Thomas , Hollaender Florian , Gringarten Alain C.
Published: December 2007

Current trends towards permanent downhole instrumentation allow the acquisition of large sets of well test data ranging over much longer periods of time than previously imaginable. Such data sets can contain information about the reservoir at a substantially larger radius of investigation than that accessible to conventional derivative analysis, which is limited to the interpretation of single flow periods at constant rate. By contrast, deconvolution methods do not suffer from this constraint as they are designed to perform well test analysis at variable flow rate.

Recently we presented a new method for the deconvolution of well test data in which the problem is reformulated as a separable nonlinear Total Least Squares problem which accounts for uncertainties in the measurement of both rate and pressure data.8 In this paper we report a number of improvements to our algorithm, and derive error bounds for rate and response estimates in the presence of uncertainties in the data, for which we assume simple Gaussian models. We illustrate our method by applying it to a small simulated example and two large sets of field data with up to 6000 hours of pressure data and up to 450 flow periods.
Effective Well and Reservoir Evaluation Without the Need for Well Pressure History
Authors: Poe B. D.
Published: December 2007

This paper presents a practical and useful analysis technique for effectively accomplishing a rigorous superposition-in-time (convolution) analysis of the transient drawdown performance of oil and gas wells that does not require that the flowing pressures (wellhead or bottom hole) be known for every flow rate data point in the production history. If at least one flowing pressure point is available at any point in time during the production history of the well, a unique analysis of the production data for the evaluation of the reservoir effective permeability, well drainage area, and well parameters such as unfractured well radial flow steady-state skin effect, fractured well effective fracture half-length and average fracture conductivity, or horizontal well effective length in the pay zone may be obtained. Even if no flowing pressures are available at all during the production history of the well, estimates of these well and reservoir parameters can still be obtained with reasonable accuracy using the analysis techniques presented in this paper.

The general evaluation procedures presented in this paper are applicable for all well types, including flowing wells and wells with artificial lift systems (i.e., conventional beam pumping units and electrical submersible pumps (ESP)). The theoretical basis for a rate-transient analysis of the production performance of a vertically fractured well is presented in detail in this paper. Application of the proposed general analysis procedure to other well types (unfractured vertical/slanted wells, horizontal wells, etc.) may also be found in a similar manner as presented in this paper. The theoretical basis for a pressure-transient based solution for a vertically fractured well is also available in the references.

In the relatively short period of time that this new analysis technique has been available, it has radically changed the way that engineers may now rigorously analyze the production performance of oil and gas wells to evaluate the well and reservoir properties from the well's production performance, as well as greatly expanding the number and types of wells that can now be considered. The new analysis techniques presented in this paper therefore represent a step-change in the petroleum industry's technical capabilities for the analysis of the production performance of oil and gas wells over that which existed prior to this work.
Application and Mechanism Studies of Clay Gum System
Authors: Wang Wei , Gu Yongan
Published: December 2007

Polymer is used for mobility control in most chemical EOR projects. However, it is sometimes unfavorable because of its chemical and mechanical degradations and its high cost and investment risk. Efforts have to be made to develop a more effective and less expensive substitute for chemical EOR. This paper presents a clay gum system, which consists of montmorillonite, alkaline and a small amount of polymer. As a uniformly dispersed colloidal system with high viscosity, the clay gum system can be used as an oil displacement agent for mobility control in a heterogeneous reservoir. This system behaves as a pseudo-plastic fluid and has similar rheological property to a polymer solution. In addition to its insensitivity to salinity, it also shows a remarkable tolerance to strong mechanical shear and high reservoir temperature. The average enhanced recovery rates of the linear and radial coreflood tests for the clay gum system were found to be 35% and 10%, respectively. The microscopic oil displacement tests were conducted in transparent micromodels with rather different wettability to visualize the flow and adsorption processes of clay gum in porous media. Some major mechanisms of clay gum system were identified in the microscopic visualization tests. In particular, the colloidization process of clay gum can be explained in terms of the well-known DLVO theory. Furthermore, industrial pilot tests have been conducted in Gudong oil field and Shengcai oil field in China since 1992. The detailed pilot test results show that the clay gum system can greatly enhance oil recovery and effectively reduce water-cut. The pilot tests in these two oil fields had already produced over 12, 700 tons accumulative incremental oil by the end of 1998.
Non-Newtonian Fluid Flow in Coiled Tubing: Theoretical Analysis and Experimental Verification
Authors: Zhou Y. , Shah S. N.
Published: December 2007

This paper presents a comprehensive theoretical study of the flow of non-Newtonian fluid in coiled tubing using the boundary layer approximation method. First, a boundary layer approximation analysis was applied to the governing equations of continuity and motion of a power law fluid in the curved tubing flow geometry. Momentum integral equations for the boundary layer flow were then derived and solved numerically. The resulting solutions of the velocity field were used to develop a new friction factor correlation in terms of generalized Dean number, coiled tubing curvature ratio, and flow behavior index of the power law model. The new correlation of this study and a previous correlation by Mashelkar and Devarajan were evaluated using experimental data obtained from full-scale coiled tubing flow experiments. An excellent agreement was found between the new correlation and the experimental results. The Mashelkar and Devarajan correlation failed to result in any acceptable agreement with the experimental data, nor did it match the Ito correlation for the Newtonian fluids (n = 1). This work extends the range of applicability of the new correlation to fluids with flow behavior indices as low as 0.25, which would cover most fluids used for coiled tubing operations in the oil and gas industry.
Fast Induction Log Inversion Using Quasi-Newton Updates
Authors: Gao L.
Published: December 2007

Interpretation of induction logging data is difficult due to its diffusive nature and its large volume of investigation. To overcome these difficulties, various techniques have been applied in the past. These techniques include deconvolution filters, least-squares inversion, inversion based on the maximization of entropy, as well as neural networks techniques. Among them, the maximum entropy method is the most robust. Unfortunately, it is computationally intensive and can only be carried out in computing centers. To reduce this intensity and accelerate the inversion process, a new method has been developed for induction log inversion using quasi-Newton updates of the Jacobian matrix. Using the new method, 200 ft of log data can be inverted in 80 seconds on a notebook computer.
An Analytic Method for Producing Multiarray Induction Logs that are Free of Dip Effect
Authors: Barber T. D. , Minerbo G. N.
Published: December 2007

Dip effect on induction tool response is a well-documented and understood environmental effect that produces increased shoulder effect at moderate dip and a complete scrambling of multiarray induction logs at high dip. Although techniques such as maximum-entropy inversion allow a full correction of the logs, these remain computer-center products that are somewhat time consuming. Wellsite inversion to correct for dip effect has remained elusive, waiting on more computer power.

In the mid-1960s Pierre Grimaldi discovered an induction measurement technique that had the remarkable property of returning the same reading in a "thin" bed that it gave in an infinite, homogeneous medium of the same conductivity. The only requirement to satisfy this condition was that the instrument sensors were all in the thin bed. The instrument configuration was such that the voltage measured was a direct solution to Maxwell's equations. Although this was a breakthrough, the instrument configuration was difficult to realize in hardware, particularly with the well-logging technology of the 1960s, and the idea was never published.

The Grimaldi configuration was independently rediscovered in the early 1980s and studied with new modeling codes. It was found that the "remarkable property" of having no shoulder effect was also approximately true at any dip angle. Again, the hardware was deemed to be impractical.

More recently, it was discovered that the array configuration of the AIT* Array Induction Imager family of tools was such that the raw array measurements data could be processed to be the same as from a Grimaldi configuration. This led to a real-time algorithm, and a set of Grimaldi curves is now available at the wellsite. This algorithm produces synthetic arrays equivalent to a Grimaldi coil configuration that solve the inverse problem without having to solve Maxwell's equations iteratively.

The Grimaldi configuration is not without its drawbacks. The logs have a shallower depth of investigation than those from a conventional induction array of the same spacing. For this reason the Grimaldi logs supplement, but do not replace, the standard AIT log sets.
Performance of IMPSAT and IMPSAT-AIM Models in Compositional Simulation
Authors: Cao Hui , Aziz Khalid
Published: December 2007

The current trend in industry is to use finer and finer grid with larger and larger number of components. This requires the development of faster simulation techniques than those currently available in commercial simulators.

The fully implicit (FIM) model, the implicit pressure and explicit saturations (IMPES) model and the adaptive implicit (AIM) model are the traditional approaches. The IMPSAT (implicit pressure and saturations and explicit component mole fractions) model has been proposed in the literatures, but so far it is not considered a viable approach. This may be a result of lack of suitable stability analysis and improper implementation. Our analysis shows that the IMPSAT model is significantly more stable than the IMPES model, and in many cases substantially less expensive than the FIM model. The IMPSAT model becomes particularly attractive as the number of components becomes large. IMPSAT can also be used in an adaptive implicit approach to form various IMPSAT based adaptive implicit (IMPSAT-AIM) models.

A new General Purpose Research Simulator (GPRS) using a General Formulation Approach has been developed and tested. The General Formulation Approach used in GPRS can be used to obtain any type of model. We can easily form a model by selecting any reasonable set of primary variables and any level of implicitness from IMPES to FIM. One important subset of models that have been developed from this new approach is the IMPSAT model and the IMPSAT based AIM models.

The performance of different compositional models has been evaluated using a wide range of problems. We found that the IMPSAT model and the IMPSAT-AIM models have very good performance, and they are more efficient than the traditional models (FIM, IMPES and AIM). The IMPSAT model is generally over 50% faster than the IMPES model due to its improved stability. For problems that are not very hard, the IMPSAT model is cheaper to run than the FIM model since it reduces the number of unknowns that have to be solved implicitly. The IMPSAT-AIM models are more flexible, more stable and with appropriate linear solvers have the potential to be less expensive in terms of CPU time than the traditional AIM model.
Process-Based Decomposition on Distributed Systems – A Strategy to Solve Large Scale Simulation Problems
Authors: Yu Mengjiao , Gadde Phani B. , Sharma Mukul M.
Published: December 2007

Large-scale simulation problems have extremely large CPU and memory requirements. Traditional methods for solving such problems involve parallel processing, which adds cost and complexity in programming. We propose a novel process based decomposition approach for distributed processing of such large-scale simulation problems. The proposed method splits up the large-scale problem based on the physics or computational units of the problem and distributes the computational load over a LAN. This method allows the problem to be solved in parallel in a distributed framework in a computationally efficient manner. The greatest advantage of this approach is that this method allows performance enhancement at little extra cost by better utilizing existing computational resources (CPU cycles). Based on the complexity of the decomposition, we categorize large-scale simulation processes into three classes. We present a distributed processor (OPTIMA) that enables application programs to be run in a distributed framework. Examples that demonstrate the efficacy of this method are presented. Results show that running the simulations in parallel on a distributed platform speeds up the process considerably with small hardware or software costs.
A Novel Approach to Gas Lift Design for 40,000 BPD Subsea Producers
Authors: Duncan G. J. , Beldring B.
Published: December 2007

Gas lift in Terra Nova production wells serves two purposes. The first is to increase the rate at which reservoir fluids can be produced, especially as water cuts increase with time and reservoir pressure diminishes. The second is to stabilize flow in the wells, flowlines and flexible risers. This paper describes the application of engineering tools to achieve an optimized subsea gas lift design for a 6350 m3/d (40,000 bpd) production rate, taking into account reservoir, wellbore, subsea and topsides constraints.
A Real Options Model for Portfolio Selection of Oil and Gas Assets
Authors: Lima Gabriel A. C. , Suslick Saul B.
Published: December 2007

Portfolio selection of oil and gas assets is a fundamental subject of capital budgeting in the energy sector. Traditional methods of portfolio selection are index ranking, zero-one programming, and utility functions. However, none of these methods mentions the value of option timing when the firm is selecting the desired combination of projects. This paper compares results of portfolio selection of non-developed reserves using both traditional approaches and option timing.
Monitoring Fracturing Fluid Flowback with Chemical Tracers: A Field Case Study
Authors: Asadi Mahmoud , Woodroof Robert W. , Malone William S. , Shaw Donald R.
Published: December 2007

Proper fluid and proppant placement is the key to a successful fracture simulation. Performance of fracturing fluids, as they are pumped into a fracture, is the key to effective proppant placement. Fracturing fluids are used to both prop open a fracture and to effectively carry the proppants and place them into a fracture and to successfully flowback to the surface. Productivity of a well, after proppant placement, greatly depends on the flowback efficiency. This paper presents a novel technique where fracturing fluid flowback can be effectively monitored in a complex multi-zone fracture system. A family of environmentally safe chemical frac tracers, with unique characteristics, is developed to assure distinction of each zonal frac fluid upon flowback. The paper also presents a case where the technique was implemented in a multi-stage-fracturing job. Various chemical frac tracers were injected during different stages, which included pad fluid and crosslinked fluid with various proppant concentrations and breaker loading. Results and fracture flowback diagnoses are presented.
Cement Pulsation Treatment in Wells
Authors: Wojtanowicz Andrew K. , Smith John Rogers , Novakovic Djuro , Chimmalgi V. S. , Newman Ken R. , Dusterhoft Dale , Gahan Brian
Published: December 2007

Cement pulsation is a novel technology for enhancing zonal isolation by applying low frequency, hydraulic, pressure pulses to the wellhead immediately after cementing. The treatment maintains the slurry in a liquid state, which transmits hydrostatic pressure downhole, and keeps the well overbalanced thus preventing early gas flow after cementing.

The paper summarizes several stages in the development of cement pulsation technology including comparison to other methods, physical principles, process analysis, mathematical modeling, computer-aided design, laboratory testing, and field performance.

The paper supports published information on cement pulsation with data from research and field studies that was instrumental in developing the technology. Emphasis has been given to the analysis of the pulsation process, description of design model and software, and an updated account of field applications.

Described is the MS Windows software for pulsation design. Two examples demonstrate the computer-aided design. The examples show that the software could be used to find the pulse size and treatment duration for a constantpressure treatment. Alternatively, a variable-pressure treatment with controlled treatment depth could be designed.

Data is presented from pulsation of over 80 wells in drilling areas notorious for early gas migration after cementing. Field applications of the technology in 80 wells provided significant evidence of the success of cement pulsation in preventing early gas leakeage in cemented wells.
Subsea Remedial Cementing of Conductors on Template-Drilled Development Wells
Authors: Reynolds D. A. , Hannestad E. , Melchiorsen J. C. , Morrison G. G.
Published: December 2007

All operators face a number of well design decisions throughout the planning and execution of a development project. Decisions based on preliminary data can subsequently turn out to be sub-optimal leading to significant problems developing after there is no straightforward way of preventing these from escalating. This paper describes how a significant structural risk evolved with the conductors in several wells of a development with no obvious method to prevent continued deterioration. It describes how a new and innovative set of equipment, known as the Annular Sealing Unit (ASU) was designed, built, tested and deployed offshore to restore the structural capability of the wells without any production or operational shutdowns occurring.

Further, it describes the details of the planning and execution of the ASU project. Lessons learned during the project will highlight how the close co-operation between the operator and service provider was fundamental in leading to the success of the project.

The experience gained from this project has demonstrated that although a significant challenge can present itself with no initial straightforward solution(s) apparent it is possible, with clearly defined roles and an open and innovative approach to the challenge, to identify and implement a new process and solve the problem in an inventive way.

Finally, this paper recognises the initial shortcomings in the development's conductor setting procedure. Although it may appear obvious with hindsight to the reader these were not apparent until well into the development and can act as a cautionary narrative as to how a fundamental well planning decision can have a far-reaching and adverse effect.
Value Created Through Versatile Additive Technology and Innovation for Zonal Isolation in Deepwater Environments
Authors: Reddy B. R. , Richard Vargo , Sepulvado Bob , Weisinger Don
Published: December 2007

Value may be created by applying innovative technology in challenging zonal isolation applications. Risk evaluation in deepwater cementing can be accomplished without jeopardizing environmental impact and cost effectiveness. Some of the highest risks encountered in deepwater cementing operations are related to low temperatures and the existence of shallow water flows (SWF). Generally, for cementing low-temperature zones, high early strength blends with set accelerators are utilized. At normal temperatures, Class A or Class H Portland cements are normally preferred in Gulf of Mexico (GOM) operations. The cement system for SWF zones should have a relatively low density and a short transition time to help maintain well control. Presented in this paper are examples of how a single cement system has been used to meet all design criteria for delivery of deepwater well cementing.

A disadvantage in using a variety of cement types and blends for cementing in an offshore environment is that the unused preblended materials designed for a given depth are often discarded, and new blends are made up for the subsequent cementing operations. This can result in increased material costs and repeated trips to shore. It is desirable, both economically and environmentally, for an operator to be able to use the same neat cement for cementing wells at multiple depths.

This paper presents details of an innovation that involves cementing offshore wells with SWF problems with only one neat cement by using versatile additive technology. Case histories for cementing several wells in the GOM in water depths greater than 2,000 ft are presented. In all cases, flowable salt-water zones were encountered while drilling. The operator's risk assessment of the problem was uncertain at the time of well design and planning because of the exploratory nature of the wells drilled. The liquid additive system for flow control gave the operator the flexibility of having the additives on the rig at the time the holes were drilled. The operator could evaluate the flow potential before deciding to use the system or use other options.

The foamed cement system used in these case studies used a liquid additive for SWF control. The remaining portions of the wells were cemented with the same neat cement by using different liquid additives. This in turn helped reduce environmental impact of wasted cement and saved the operator considerable capital for the wells drilled.
Konsas: An Exhaustive Reservoir Model to Evaluate the Contribution of Seismic to Reservoir Characterization
Authors: Andrieux Benoît , Fournier Frédérique , Cailly Frédéric
Published: December 2007

Konsas is a realistic 3D synthetic reservoir model constructed from a real data set . The geological environment of the actual reservoir is a mixed carbonate platform, with tidal to supra- tidal deposits of limestones, dolomites, anhydrite, and sandstones. The Konsas model corresponds to a particular realization of a geostatistical model based on the actual field data. The thickness of the reservoir interval is approximately 100m, with a geometry derived from markers and associated seismic horizons picked on the real seismic data. The reservoir is described in terms of lithofacies, and related porosities and acoustic impedances, with a gridding of 12.5m in the horizontal directions and 1m in the vertical direction, allowing to generate realistic fine-scale heterogeneities. The post-stack seismic image of the reservoir was generated with a 1D convolution, the seismic wavelet being derived from the real seismic data.

The Konsas model is used for better understanding the link between the reservoir properties and their seismic responses. In particular, standard techniques used in lithoseismic interpretation were applied to predict the average porosity variations at the reservoir level from the seismic variability. In this interpretation, only a few "wells" -vertical columns extracted from the 3D model- were used. The lithoseismic interpretation included statistical estimation techniques (linear regression and cokriging), and seismic facies analysis based on a pattern recognition approach. The seismic-derived porosity was compared with the exact porosity distribution for both approaches (statistical estimation and seismic facies analysis). It confirms that despite the limited number of wells, and the bandwidth restricted with respect to the reservoir heterogeneities, seismic data still provides valuable information in the interwell space. However, in this kind of seismic interpretation, some parameters are of crucial importance and should be carefully analyzed, such as the correlation trends. Moreover, Konsas has allowed to illustrate that the calibration population on which the statistical models are established should be representative of the whole reservoir as much as possible. The data should also be stationary as far as possible. For these two issues, the interpretation of the Konsas synthetic data set has shown how a seismic facies analysis could be used. The impact of the seismic attributes chosen to build the statistical model was also discussed, demonstrating the importance of testing the very low frequency component influence, when using attributes derived from the impedances.

The lithoseismic interpretation of the Konsas model has also demonstrated the strong convergence between the results of the estimation techniques and those from seismic facies analysis. It confirms the great interest of this last approach for lithoseismic interpretation, since it remains feasible and robust, even with a very limited number of wells.