bluuebunny/crossref_metadata_2025_split 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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.