bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimization of Acid Fracturing Program In the Khuff Gas Condensate Reservoir of South Ghawar Field Saudi Arabia by Managing Uncertainties Using State-of-the-Art Technology
Authors: Al-Qahtani Mohammed Y. , Rahim Zillur 
Published: December 2007

Abstract
The Khuff reservoir in South Ghawar, Saudi Arabia is a heterogeneous tight carbonate reservoir. Acid fracturing program has been initiated to enhance gas production from this reservoir to deliver 1.2 BSCFD of gas. The complex nature of the tectonic stresses, geomechanical properties, reservoir geology and quality, coupled with aerially varying fluid properties (H2S) have sometimes reached the limits of reservoir simulation and stimulation.
During the early stages of development, numerous diagnostic tests were conducted on every well before, during, and after fracture treatment. These tests include pre- and post-fracture pressure transient analysis, radioactive tracer or temperature log runs during mini and main fracture treatments, production tests, and production logging. Several acid fracturing fluids, such as, 28% HCl, emulsified 28% and 15% HCl, were applied to achieve optimum fracture length and conductivity, and avoid CO2 corrosion. Complete reservoir characterization, history matching of actual fracture treatment and production forecasts were performed for every well. The objective of these tests and detailed evaluation is to optimize future acid fracture design.
This paper presents in detail the integrated optimization process of acid fracturing in the Khuff reservoir. The paper demonstrates that early investment in technology, management of uncertainties, and state of the art reservoir and fracture modeling significantly improved the optimization process.
The paper presents detailed assessment of several key wells, comparison between various acid fracturing fluids and techniques, and calibration of results of the stress and fracture models. The paper also discusses the need and importance of some of the tests and the quality of the results that may be obtained from them.
Finally, the paper presents reservoir modeling and history matching of acid fracture treatment using state of the art coupled geomechanical single well simulation model. Predictions of acid fracture performance versus time under the Khuff abnormal stress conditions are presented.
Using Magnetic Resonance Logging to Evaluate Permeability of a Carbonate Reservoir Containing Highly Viscous Oil: A case Study
Authors: Hassan Medhat , Nour Mohamed , Zeidan Selim , Elsherif Ahmed 
Published: December 2007

Abstract
The study reservoir is the Thebes formation of early and middle Eocene age. It was recently discovered in the south Geisum area, Gulf of Suez. The rock formation was deposited in a shallow marine environment and is composed mainly of cherty limestone of complex nature.
In GB-1 well, we have carried out a formation evaluation program to appraise the Thebes discovery using traditional open hole logs in addition to the newly introduced technologies, the Nuclear Magnetic Resonance and the Dipole Sonic measurements.
Eventually, two intervals were perforated and tested. The DST gave a permeability of around 5 md and 70 md for the lower and upper zones respectively. The Magnetic Resonance calculated permeability was around 1 md and 4 md respectively. The produced oil was highly viscous. The Magnetic Resonance was reinterpreted to determine the effect of the highly viscous oil on the permeability calculation.
In field practice, a T2 cut-off of 100 msec is used for carbonate reservoirs. In general, the oil bulk relaxation falls in the free fluid area. However, for 28 cp oil viscosity, the bulk relaxation time for the oil is around 40 to 60 msec. This means that the oil signature is coming inside the bound fluid volume, although it should be free since we assume the rock is water wet.
The oil volume in the invaded zone was deducted from the bound fluid volume and then added to the free fluid volume. The Timur-Coates permeability equation was then used to re-calculate the formation permeability using the adjusted volumes of bound and free fluids, thus resulting in permeability corrected for the viscous oil effects. The recalculated permeability showed a good match with the permeability obtained from the drill stem test data.
Capillary Pressure Data from NMR Logs and Its Implications on Field Economics
Authors: Altunbay M. , Martain R. , Robinson M. 
Published: December 2007

Abstract
The analogous behaviors of capillary pressure and 1/T2 decay versus saturation data provide a methodology for deriving synthetic capillary pressure information directly from NMR logs even if core data are not available. Estimations of irreducible water saturation4 from NMR log-based synthetic capillary pressure profiles have numerous benefits. One benefit is the enhanced accuracy of permeability estimations by using synthetic bulk volume irreducible in the bound water model. Availability of synthetic bulk volume irreducible data from capillary pressure modeling eliminates the requirements for determining the T2cutoff time from core analysis data or assuming generally accepted constants for it (33 ms for clastics and 92 ms for carbonates). In addition to the bound water model, an alternative permeability profile can also be generated from Purcell's7 capillary pressure-permeability relation. Another benefit derived from a synthetic capillary pressure profile is the determination of Oil Water or Gas Water Contact (OWC, GWC) by simply converting the capillary pressure information to height above free water level. This information can also be compared with the Free Water Level (FWL) from formation test tools. The relative positions of FWL and OWC assist in inferring wettability14 and the degree of wettability magnitude for the subject reservoir.
Relative permeability estimations from synthetically created capillary pressure data provide an avenue to make the firstapproximation profiles of the effective permeability values to the phases contained in the pore space. Consequently, effective permeability profiles in conjunction with other petrophysical and fluid properties and the pressure information lead to the anticipated production rates and overall evaluation of the economic viability of a well(s) and field. Applications of the technique with inherent assumptions, limitations, and remedies for the limitations are reviewed and explained through a case study presented in this paper.
Array Induction Measurements in Complex Environments: A Comparison Between AIT and HDIL Responses
Authors: Gonfalini M. , Galli M. T. 
Published: December 2007

AbstractWith the recent introduction in the oil industry of multiple-frequency, multiple-coil Array Induction tools, the vertical resolution and range of resistivity measurements have been improved by the use of well site processing based on the Born approximation.By using this technology, we can obtain several resistivity curves with different depths of investigation, and matched vertical resolution of 4, 2 or 1 ft., directly at the well site: this looks promising not only for obtaining true resistivity (Rt) measurements, both in low and high resistivity environments and even in the presence of thin beds, but also for improving the characterization of complex invasion profiles.Nevertheless, with the experience developed in recent Array Induction acquisitions in many different operational environments, we are now aware of the fact that the quality of such measurements is strongly affected by the presence of dipping beds and very high resistivity contrasts.This reduction in quality is mainly related to the signal processing techniques used at the well site which can not be completely suitable for all geological environments.This paper presents:the results of a comparison among Array Induction acquisitions from wells with Oil Based Muds, by using both AIT and HDIL tools, in different geological environments;the results of the quantitative evaluation of Water Saturation in the reservoirs.All measurements were taken in clastic reservoirs in Italy.The paper provides also some information about the available corrections that may be applied to the measurements, in a post-processing phase, to improve the quality of the petrophysical interpretation, and about the use of Resistivity Modeling techniques to better understand the physical behavior of the tool responses.The conclusions achieved are aimed at optimizing the use of all available technologies in future operations in similar environments.
Field Applications of a New Nuclear Magnetic Resonance Fluid Characterization Method
Authors: Freedman R. , Heaton N. , Flaum M. 
Published: December 2007

AbstractThis paper discusses the application of a new magnetic resonance fluid (MRF) characterization method to field data acquired by a nuclear magnetic resonance (NMR) well logging tool. The theoretical and experimental foundation underlying the method was discussed in a paper presented at the 2000 SPE meeting.1 The MRF method provides a detailed formation evaluation of the near wellbore region investigated by modern NMR logging tools. This information includes total and bound-fluid porosities, hydrocarbon saturations, oil viscosities and hydrocarbon-corrected permeabilities.In this paper we first provide a short review of the main ideas and key equations that make up the MRF method. We discuss the generalization of the MRF method to logging data acquired by the CMR* Combinable Magnetic Resonance tool and apply the method to mixture data acquired by a CMR tool on crude oil and water samples.We also discuss the existing database of MRF results on partially saturated rocks, and present new laboratory results that include blind tests on Yates field dolomite rocks measured at initial and residual oil saturation.The sources of uncertainty inherent in NMR diffusion-based viscosity estimation in reservoir rocks are discussed, and we propose a strategy that accounts for the uncertainties and provides "best estimates" of oil saturations and viscosities. The strategy is applied to the MRF analysis of the field data in this paper.The MRF method is applied to CMR station log data acquired in three wells. Analysis of the MRF data and the results from each of these wells is discussed.
Field Experience with a New Carbon/Oxygen Logging System in Complex Wellbore and Formation Conditions
Authors: Simpson Gary A. , Truax Jerome A. , Younse Gary A. 
Published: December 2007

Abstract
Carbon/oxygen (C/O) tools have been designed for helping evaluate reservoirs under relatively simple conditions, such as cased wells with tubing removed and a single fluid present and reservoirs that have relatively high formation porosity. However, to reduce costs, tubing is often not pulled and wellbore conditioning is minimized. A new generation of small-diameter C/O tools capable of logging through-tubing has therefore been developed to deal with these circumstances. Logging through-tubing, despite its advantages, presents its own set of problems. Obtaining reliable measurements is often highly challenging because of different tubulars, various borehole fluids, and multiple contacts in a single well.
A new high-resolution C/O system has recently been developed for use under such complex conditions, specifically in tubing of 2⅞-in. and larger diameters with various fluids in the tubing/casing/formation. The tool has been run successfully in borehole conditions with wells flowing and shut-in. Sometimes the conditions included multiple wellbore contacts of gas, oil, and water within casing and multiple contacts in a tubing/casing annulus. Despite the various and changing borehole environments encountered by this tool, advanced electronics and detector designs, careful characterization, and comprehensive software have resulted in high-quality measurements.
This paper illustrates performance of the new C/O system under extremely inhospitable conditions in the Asia-Pacific area. Conditions include multiple contacts with water, oil, and gas in the borehole, as well as multiple contacts with water, oil, and gas in the tubing/casing annulus. Furthermore, reservoir porosity in the subject borehole was in the low range of 8 to 15%, where success with C/O logs has previously been minimal. Nevertheless, the tool obtained extremely useful data that provided an accurate assessment of the reservoir conditions, and thus allowed decisions to be made for secondary workovers and other reservoir product management remedies.
Real-Time Geological Positioning of a Well in the North Sea
Authors: Schroeder Tom , Boonen Paul , Illfelder Herb , McElhinney Graham , Templeton Gerhard 
Published: December 2007

Abstract
This paper describes the pre-job and real-time geological modeling of a horizontal well in a field in the North Sea. Using the PayZone Steering™ (PZS™) system, LWD gamma ray and resistivity data were used to continuously locate the wellbore in the geological section, modifying the geologic model in real-time as needed. Drilling was assisted by the real-time transmission and display of the LWD information, including downhole pressure and computed ECD, at multiple locations both onshore and offshore.
The well was planned to develop the Brent Sand by traversing two fault blocks, the second being downthrown and the primary target. The original geologic interpretation suggested major lithologic and stratigraphic differences between the two blocks. Therefore pre-job modeling was performed using three offset wells within the second fault block.
In the drilled well, the formation in the second block proved approximately 20 meters higher than expected as confirmed by comparison with the offset wells. Significant facies changes in the channel sands made detailed correlations with the offset wells difficult. Fortunately for concurrent detailed analysis, the geology in both blocks proved similar and the drilled well penetrated the target sand in both the upthrown and downthrown blocks. As a result, the LWD logs acquired in the first (upthrown) block provided the best correlations with the horizontal section, allowing for accurate determination of the well's geologic position.
The project team was thus able to successfully detect formation tops that were different from the modeled geology, continuously locate the position of the wellpath in the geologic section, and update the geologic model in a timely fashion. This information was then used to dynamically modify the drilling program.
Sensitivity Analysis of Horizontal Well Productivity under Steady-State Conditions
Authors: Shedid Shedid A. , Zekri Abdulrazag Y. 
Published: December 2007

Abstract
Many horizontal wells are being drilled all over the world to increase their productivity in comparison to that of vertical wells. Horizontal wells increase reservoir contact area and thus increase productivity. Therefore, it is essential to be able to predict the horizontal well productivity. The major objectives of this investigation are to: (1) develop a comprehensive evaluation of currently-used steady-state productivity equations of horizontal well, (2) investigate the effect of horizontal well length and pay zone thickness on the productivity ratio of horizontal well to vertical well, when both having the same drainage area and under identical flow conditions, and (3) study the influence of pressure drop on production rate of horizontal wells using different steady-state flow equations.
In this study, six different steady-state equations of the open-hole horizontal wells under identical conditions of flow parameters and reservoir geometry are subjected to a wide ranges of horizontal well lengths (100 to 3,000 ft), pay zone thickness (50 ft to 500 ft), and pressure drop (10 psi to 200 psi). These horizontal wells were used to calculate the productivity and to study the influences of flow rate and pressure drop on the sensitivity of these equations.
The obtained results showed that all steady-state equations provide similar horizontal well productivity for horizontal well length &lt; 1000 ft, while a remarkable difference appears and increases when well length increases &gt; 1,000 ft. In addition, the results using all steady-state equations confirmed the recommendation of the application of horizontal well for thin formations and do not recommend it in thick ones (h &gt; 250 ft) for wells having identical rock and fluid properties. Comparing the performance of steady-state equations showed that all of these equations are sensitive to the increase of pressure drop, which yields an increase in flow rate of horizontal well. The results of this study have important implications in reservoir simulation studies, since it evaluates some important variables including pay zone thickness, well length, and pressure drop on the performance of each flow equation.
Multiphase Pumps for Light Oil Steam Flood, from Design and Operation Perspectives
Authors: Putra Erwinsyah 
Published: December 2007

Abstract
Caltex Pacific Indonesia began operation of a Light Oil Steam Flood (LOSF) project in the Minas Oil Field, Sumatra. Multiphase pumps (MPP) are utilized as the casing vapor collection system. Three twin-screw MPP's have successfully operated since June 2000. The MPP's were designed to handle high sand-rate. By means of closed loop control, the MPP's actively control production wellhead pressure, critical for optimizing electrical submersible pump operation in the tubing side. Closed loop control also provides the ability to handle hydrodynamic slugging in the incoming lines. This paper describes the design, testing and successful field operation of the Multiphase pumps in the Minas Light Oil Steam Flood Project.
Cementing Considerations for Deep Wells in the Appalachian Basin
Authors: Peters F. W. , Schindler R. 
Published: December 2007

Abstract
As drilling operations penetrate deeper horizons in the Appalachian Basin, wellbore construction faces new challenges. Larger and deeper hole sections, higher temperatures, higher formation pressures, and naturally flowing high rate gas zones result in wells that cannot be properly or safely completed with conventional Appalachian Basin cementing techniques.
An Analytical Model for Gas-Water-Coal Particle Flow in Coalbed-Methane Production Wells
Authors: Guo Boyun 
Published: December 2007

AbstractCoalbed methane (CBM) plays an important roll in US energy market. Prediction of CBM well performance is vitally important for enhancing CBM production. It is highly desirable to have a simple and accurate tool to do the prediction job.Assuming homogeneous mixture flow of liquid, gas, and solid in pipes, a simple analytical model was developed for simulating 3-phase flow in production strings. Liquid holdup effects were considered by applying a tuning factor to friction factor. The tuning factor was defined as a function of gas-liquid ratio (GLR) and vertical depth. The analytical model was coded in a spreadsheet program and calibrated with measurements from a full size physical well model. The calibrated analytical model was used for predicting performance of CBM wells during gas-lift dewatering operations and proven to be accurate for upward flow of CBM gas and water in a 2-7/8" tubing.
Use of Wellhead-Pressure Data to Establish Well-Inflow Performance Relationship
Authors: Guo Boyun 
Published: December 2007

AbstractInflow performance relationship (IPR) of wells is an essential piece of information required in production well modeling and optimization. A reliable IPR is usually established based on bottom hole pressure measurements. However, such measurements are often very expensive. It is highly desirable for production engineers to be able to establish well IPR from wellhead-pressure measurements.This paper demonstrates that a mechanistic model originally developed for modeling gas, water, oil, and solid particle 4-phase flow in borehole drilling can be employed for establishing IPR of oil wells when bottom hole-pressure measurements are not available. Two cases with field measurements are presented. The results indicate that, using the 4-phase flow model, the well IPR curves constructed based on the wellhead-pressure measurements are accurate. The error in bottom pressure prediction is less than 2%. The error in productivity index determination is less than 10%.
4-D Mapping of Porosity and Investigation of Permeability Changes in Deforming Porous Medium
Authors: Karacan C. Ozgen , Grader Abraham S. , Halleck Phillip M. 
Published: December 2007

Abstract
Reservoir rock near wellbore experiences substantial changes in the poroelastic stress field due to presence of the well itself and later to changes in effective stress conditions as reservoir pore pressure is depleted. Hydraulic fracturing or other stimulation treatments may introduce further stress changes. Although such stress changes may lead to macroscopic rock failure, even under less severe loading, substantial changes in the pore structure. Such stress- and time-dependent deformation of the porous structure is known to change important properties of the rock such as porosity, and permeability.
In this study we investigate the porosity and permeability changes in deforming porous rock using X-ray CT imaging. We used a specially designed X-ray-transparent tri-axial cell enabling fluid flow at the same time. We scanned the samples at successively higher differential stress to observe stress-dependent changes in porosity and permeability. Since the presence and value of confining pressure changes the deformation behavior of the rock, we applied different constant confining stresses on the samples to change the deformation regime and map the porosity in the failure regions.
Results showed that the stress condition applied to the porous medium changes the rock and fluid transport properties compared to the sample measurements done without stressing the sample. Medical and industrial high resolution X-ray scanners enabled us to quantify and map local porosity changes, locate compaction band and where shear location occur and how the inner structure of the rock changes during different modes of deformation. We also compared the properties of sandstone with limestone under deforming stresses.
A Comprehensive Approach to Completion Optimization
Authors: Venkitaraman A. , Manrique J. F. , Poe B. D. 
Published: December 2007

Abstract
The completion selection process is a critical step in ensuring well productivity. It is shown how this can be optimized by a decision tree based approach along with a combination of predictive analytical tools.
The completions are broadly divided into those that would be limited by sanding issues over the producing life of the well as opposed to those that would not. Available sanding prediction models are used for this decision step. For wells where sanding could be an issue two separate options are analyzed: sand control and sand prevention. Sand control implies completions that incorporate some means to physically prevent the transport of sand along with the flowing fluid. On the other hand sand prevention uses predictive models to generate completion and production parameters that minimize the risk of sand production. Where sanding is not an issue, traditional completion options are evaluated: open-hole, natural (cased-perforated) and stimulated (fractured) completions.
Once the above process is complete, the best completion option is determined using three steps: i) quantifying the impact of different options on well productivity, ii) production forecasting, and iii) economics and risk analysis. Predictive tools combined with prior experiences are used to determine the impact of different completion choices on well productivity. Using this information single well production forecasting is carried out using mathematically rigorous and computationally efficient well performance simulation model. Lastly, economic analysis that combines the upfront costs and predicted production data is used to determine the best completion choice for the well. In addition to economic analysis, this step also considers risk - in the form of uncertainty in key parameters.