bluuebunny/crossref_metadata_2025_split huggingface dataset:
Determining Consistently the A Priori Information Weight in a Stratigraphie Inversion
Authors: Fournier F. , Perdrizet T. , Royer J. J. 
Published: December 2007

Abstract
Stratigraphie inversion of seismic amplitudes is a widely-used technique for estimating acoustic or elastic impedances, these impedances being related to reservoir properties in a second step. For inversion processes incorporating a priori information, it is very important to weight the a priori in the cost function, consistently with the a priori uncertainties. The a priori model is built from kriging impedance values at wells along stratigraphic correlation surfaces. The covariance of the kriging error is derived from a theoretical analysis. This covariance is approximated either by a stationary or by a locally-stationary exponential covariance. In both cases, the parameters (range and standard deviation) of the approximated covariance are a priori weights consistent with the true spatial structure of the a priori uncertainties. This methodology significantly changes the a priori weights, that were before simply user-defined, leading therefore to a different estimated impedance field, more coherent with all integrated data.
Water-Based Formation Imaging and Resistivity Logging in Oil-Based Drilling Fluids-Today’s Reality
Authors: Laastad H. , Haukefaer E. , Young S. , Tehrani A. , Delaunay P. , Feather K. , Phillips J. , Marca S. 
Published: December 2007

Abstract
Historically, acquiring borehole image logs and resistivity at the bit measurements of useable resolution have been difficult, if not impossible, when using oil-based drilling fluids. Conversely, in many applications, drilling objectives and other performance criteria prohibit the use of water-based fluids, which deliver logs of higher resolution.
Azimuthal borehole images in oil-based mud systems are delivered by wireline conveyed ultrasonic measurements or azimuthal density measurements made while drilling. Higher resolution images have generally been out of reach in oil-based systems because the measurement technology used to deliver these services involves passing electric current through a conductive borehole fluid.
Resistivity-at-bit devices used for geostopping and geosteering also rely on electric current transmission from the bit to the formation and are optimized for a conductive mud system. In many applications, drilling objectives and other performance criteria prohibit the use of water-based fluids, thus placing high-resolution images, resistivity-at-the-bit, and the high-value applications that these services can deliver out of reach of the reservoir evaluation and well placement teams.
This paper describes the development and successful application of a conductive oil-based drilling fluid system that produces water-based logging quality and enhanced geosteering without sacrificing the performance advantages of invert-emulsion fluids. This unique system, employs an electrically conductive continuous phase that provides a high-performance fluid with a conductive mud, filter-cake and filtrate. The authors detail the development of the system, which included a yard test where fluids of varying conductivity were circulated through a test well with formation micro imager response determined and compared against measured conductivity.
Further, the authors discuss the application of this new system on the Gullfaks South in the Norwegian sector of the North Sea, where the fluid was used to drill a highly deviated well through complex geological structures. In this application the fluid showed the drilling performance expected from an invert-emulsion oil-based fluid (i.e. high penetration rates, wellbore stability and low torque/drag). Results from formation micro image logs and resistivity-at-bit measurements taken using this fluid are presented and discussed.
The authors also review lessons learned in the development and field application of this conductive fluid, and address current limitations and future developments.
Multivariate Statistical Analysis Improves Formation Damage Remediation
Authors: Tague J. R. 
Published: December 2007

Abstract
The design and implementation of remedial techniques used to overcome formation damage can be costly and time-consuming. In formations with multiple formation damage mechanisms, the challenge becomes even greater. In many cases, numerous trials must be conducted to determine the appropriate treatment. Even then, distinguishing the important variables can be difficult. In the past, this has led to suboptimal design and poorly defined candidate selection criteria.1 Fortunately, multivariate statistical analysis can greatly simplify the task. Several useful forms of multivariate statistics include correlation matrices, multiple regression, and experimental design. Correlation matrices can quickly identify variables that are critical to success. Multiple regression can build upon the initial analysis and calculate potential results based on selected variables. Finally, experimental design can be used to reduce the overall number of remedial attempts necessary to determine critical success factors.
This paper will introduce the concept of multivariate statistical analysis and describe the multivariate techniques that can be used to improve formation damage remediation. In addition, actual examples will be presented of multivariate analysis used to improve acid treatments, solvent washes, and several other forms of remediation used in the West Coalinga field – a field known for its multiple formation damage mechanisms. Overall, this paper should provide a solid background for anyone who wishes to use statistical analysis in their efforts to improve formation damage design, treatment, and implementation.
The Dynamics of Electric Submersible Pump Populations and the Implication for Dual ESP Systems
Authors: Sawaryn S. J. 
Published: December 2007

Abstract
This paper contains analytical expressions illustrating the growth, renewal and decline of single Electrical Submersible Pump (ESP) populations and their transition to dual ESP systems. Critical assumptions are justified using published data. The commercial implications of the conclusions are presented. Discussion starts with possible misinterpretations of Instantaneous Run Time, which is a commonly adopted measure of pump reliability. Statistical renewal theory is then used to quantify the sensitivity of workover delay time to rig availability and to determine the expected change in failure rates when replacing an existing pump population with more reliable units. The transition is shown to be relatively insensitive to even large improvements in reliability.
Dual ESPs are considered as a means of improving runlife. When analysed as a stand-by redundant system they are predicted to exhibit a gamma distribution. Under certain conditions, the replacement of an existing pump population with dual ESPs is predicted to result in a faster reduction in the workover rate and confer additional commercial benefits compared to a single ESP with the same mean time to failure (MTTF). The first dual ESP system for the Milne Point Field (MPU), Alaska was successfully run in a Kuparuk well in April 2000.
It is concluded that dual ESP systems deserve greater consideration. The material is of interest to vendors designing ESP systems and those managing fields utilising ESPs, particularly those involved in incentive based contracts.
Using the Cased-hole Formation Tester Tool for Pressure Transient Analysis
Authors: Hurst S. M. , McCoy T. F. , Hows M. P. 
Published: December 2007

Abstract
This paper presents three pressure transient analysis case histories using a wireline cased-hole formation tester (FT) as part of an appraisal program in the Peng Lai 19-3 field, offshore China. A typical cased-hole formation test operation involves perforating a 1-foot interval via wireline, setting the testing tool across the perforations with straddle packers, and pumping formation fluids through the tool to catch representative samples. Although the main goal of the cased-hole wireline formation test program was to obtain fluid samples, short pressure buildups lasting approximately 2 hours or less were also conducted. We found the character of the pressure data and the resulting transient analyses to be comparable to those from cased-hole drillstem tests (DST's).
Wireline formation testers have traditionally been used in open-hole to gather formation pressures and collect fluid samples. On a limited scale, the pressure data have provided information about reservoir properties from pressure transient analysis. However, it is difficult to run these tools in some types of formations (unconsolidated sand, unstable shales) because of collapsing formations, differential sticking, and sand production. The Peng Lai 19-3 Field consists of a series of stacked, unconsolidated sandstone reservoirs having wide variations in oil PVT properties with depth. Using the cased-hole FT tool offers a significant cost saving by reducing the number of drillstem tests required to characterize these stacked reservoirs. This paper will (1) describe the tool setup and procedures used to collect the fluid and pressure data and (2) present the pressure transient analysis of the data using traditional methods (log-log and semi-log techniques).
Triple Frac-Packing in a Ultra-deepwater Subsea Well in Roncador Field, Campos Basin - Maximizing the Production Rate
Authors: Rovina Paulo S. , Pedroso Carlos A. , Coutinho Arthur B. , Neumann Luis F. 
Published: December 2007

Abstract
The key issue to develop the Roncador field, located in ultra deep water offshore Campos Basin, in Brazil, is the maximization of production rate keeping the completion reliability, avoiding premature high workover costs involved in that scenario. Roncador reservoir has a succession of thick turbidite sandstones containing 31° API oil, requiring sand control and water injection to maintain reservoir pressures above saturation’s. The distance between the pay zones are as short as 12 meters, becoming the first problem to fit the gravel assembly in such a short space. Flexibility in the completion is provided by an internal string with sliding sleeves. When water coning occurs in any zone, the sleeves shall be closed using slick line in a light workover.
The paper will describe the main challenges to carry out three stacked frac-packs in a subsea well drilled in water depths above 1800 m, considering the experience acquired from the first three deviated subsea wells, working in dynamic positioned rigs. Special procedures were adopted to prevent failures during the completion, such as: rigid control of fluid cleanness and gel properties, selection and operation of service tools suitable to that environment (heaving, risk of rig drive-off) and careful design for frac-pack based on minifrac data.
The drives for equipment selection will be reviewed, including the choice of perforation charges, gravel equipment and sliding sleeves. The good results obtained in those frac-packs, using the Tip Screen Out technique, reducing the skin effect compared to conventional gravel pack, will be presented too.
Application of 3D Streamline Methodology in the Saladin Reservoir and Other Studies
Authors: Chakravarty A. , Liu D. B. , Meddaugh W. Scott 
Published: December 2007

Abstract
A study of the Saladin (Barrow Group) reservoir (off shore Western Australia) was conducted using the 3D Streamline Simulation (3DSM) in 1998. This reservoir was in a harvest mode and therefore it was deemed important to investigate any remaining potential prior to abandonment. The reservoir has been on production since December 1989 entirely under primary depletion supported by an extensive and strong aquifer. Current recovery factor is over 70%!
The study was initially conducted using a standard finite difference simulator but lengthy run times were encountered. Due to project time constraints a 3DSM model was constructed and tested. This model was found to be stable with significantly shorter run times. A very good history match was achieved in a short time and the results indicated two distinct areas of significant bypassed oil. The history matched model data was then converted into the finite difference model. An almost identical history match solution was achieved quickly but at significantly longer run times.
As a result of this modeling, drilling during mid-1999 in one of the recommended target areas has yielded significant recovery of bypassed oil.
This paper will highlight 3DSM (based on Reference 1) and its applicability to other reservoirs via the Saladin study. Other applications (e.g. geostatistical model screening.) currently being undertaken using this methodology will also be discussed along with comparisons to finite difference simulators. Conclusions will also be presented on the advantages and impact of using this methodology for reservoir studies.
The Application of Stand-alone Injection Systems in Remote and/or Highly Populated Areas Reduces Construction Costs
Authors: Al-Gamber Abdulwafi A. , Al-Towailib Abdulazeem A. , Al-Wabari Saeed H. 
Published: December 2007

Abstract
This paper discusses the successful application of a standalone injection system to provide pressure support for Hanifa reservoir of Abqaiq Field, Saudi Arabia. This stand-alone injection system is a cost-effective method to provide localized powered-water injection for areas inaccessible by pipelines or costly to tie to the centralized injection facilities. Such a system has recently been successfully deployed for developing part of Abqaiq Field overlain by a residential area. The reservoir under development is relatively tight that would not effectively respond to the prevalent simple gravity dump flood, as is the case for the overlaying high-permeability Arab-D reservoir. The system consists of a single well that serves as the water supply and injector in one, and a horizontal pump. The well has a dual completion across a shallow aquifer and the target reservoir. A tubing and packer allows aquifer water to free-flow behind the tubing to a skid-mounted surface horizontal pump, where it is then boosted and injected back through the tubing to the target reservoir. The introduction of this system in a pilot well and two subsequent completions has resulted in significant cost savings versus the conventional tiein to the centralized injection facilities. The construction of a potentially hazardous high-pressure flowlines across the population center has been avoided, while allowing the development of this part of the field, which, otherwise, would require the more expensive extended reach drilling.
Improving Sandstone Matrix Acidizing for Oil Wells by Gas Preconditioning
Authors: Aggour M. A. , Al-Muhareb M. A. , Abu-Khamsin S. A , Al-Majed A. A. 
Published: December 2007

Abstract
Experience has shown that for sandstone formations, oil wells respond to matrix acidizing in a different manner as compared to gas wells. For oil wells, the improvement in permeability resulting from the stimulation treatment peaks at a certain acid volume and then drops as the volume of acid injected increases. For gas wells, however, the resulting improvement in permeability is roughly proportional to the volume of acid injected, and is normally better than that obtained with oil wells. It is, therefore, expected that stimulation of oil wells in sandstone formations could be improved by displacing the oil in the zone to be acidized with gas. Gas injection prior to acidizing is sought to minimize the formation of emulsions or sludges between the spent acid products and the oil that otherwise would be contacted.
This paper presents the results of an experimental investigation on the effect of gas pre-conditioning of the damaged sand on permeability improvement by matrix acidizing. Experiments were conducted on Berea sandstone cores saturated with 29.2 °API crude oil at selected reservoir conditions of 180 °F and 3000 psi pore pressure. Carbon dioxide and nitrogen were separately used for pre-conditioning prior to stimulation and the results were compared against stimulation without gas pre-conditioning.
It was found that with regular stimulation, improvement in permeability peaked at a certain acid volume. With gas (CO2 or N2) pre-conditioning, however, continuous improvement in permeability was obtained with increasing the volume of acid injection. Further, using gas pre-conditioning with a small volume of acid (that would otherwise not be sufficient to even recover the original permeability with regular acidizing) resulted in permeability improvements of up to 200% of the original pre-damage permeability. At an acid volume that would just restore the original permeability with regular stimulation, gas pre-conditioning resulted in permeability improvement close to 300% of the original permeability. Preconditioning with either CO2 or N2 provided superior results compared to regular stimulation. However, CO2 was found to be more effective than N2. This is attributed to the fact that CO2 has better miscibility than N2 and would, therefore, provide more efficient displacement of the oil out of the zone to be stimulated.
Shallow Gas Kick: Simulation and Analysis for Top Hole Drilling Without a Riser
Authors: Marken Craig , Hansen Svein , Øregaard Jakup 
Published: December 2007

Abstract
The influx of a shallow gas kick during top hole drilling operations without a riser can result in critical well control and safety problems for both the drilling rig and personnel. With appropriate well planning tools these top hole challenges and possible corrective actions can be addressed prior to and during these drilling operations. Based on modifications to an existing gas kick simulator package, such a well planning tool has been developed and demonstrated for the simulation and analysis of possible shallow gas kick scenarios.
Although this tool was initially intended for an analysis of the potential for elimination of the pilot hole, the emphasis of this study became the safety limits of the pilot hole itself. The simulations show the threshold levels for uncontrolled blowouts as a function of gas zone formation permeability and gas pressure when using a 9 5/8" pilot hole. A comparison with a larger 17 1/2" hole has demonstrated the lack of shallow gas kick control at the same permeabilities and even lower gas pressures. Dynamic circulation control of a shallow gas kick as a function of time after penetration of the gas zone, irrespective of when a kick is detected, shows the advantages of the pilot hole. However these advantages must be tempered by the realization of a very short reaction time.
The additional hydrostatic pressure resulting from suspended cuttings can make the difference between the control of the shallow gas and uncontrolled kick. After penetrating the gas zone circulating the cuttings out of the annulus to clean the hole can reduce the downhole pressure sufficiently to initiate a blowout while otherwise maintaining the circulation rate that would control the shallow gas.
Although the pilot hole reduces the potential for a shallow gas kick, its presence, even with careful attention to drilling operations and practices, can lead to a false sense of security. This simulator has been a valuable tool for safety analysis and planning of top hole drilling operation where shallow gas zones are a part of the formation prognosis.
Adapting Probabilistic Methods to Conform to Regulatory Guidelines
Authors: Acuña Herman G. , Harrell D. R. 
Published: December 2007

Abstract
Probabilistic methods have introduced inconsistent interpretations of how to apply these methods while complying with reserve certification guidelines. The objective of this paper is to present and discuss some pitfalls commonly encountered in the application of probabilistic methods to evaluate reserves. Several Regulatory Guidelines that should be followed during the generation of recoverable hydrocarbon distributions are discussed. An example also is given to understand the evolution of reserve categories as a function of probabilities.
Most of the conflicting reserve interpretations can be attributed to the current SPE/WPC reserve definitions where reserve categories are expressed in terms of probabilities of being achieved. For example, proved reserves are defined as those hydrocarbon volumes with at least a 90 percent probability of being equaled or exceeded (P-90). Unfortunately, these definitions alone fall short as guidance on how to derive the distributions from which these percentiles will be calculated. A simple example of this problem is the derivation of an exploratory prospect hydrocarbon resource distribution. While a P-90 can be calculated from this distribution, no proved reserves should be assigned to the prospect until it has actually been drilled and proven economical.
A Simple and Accurate Description of Non-Linear Fluid Leak-Off in High-Permeability Fracturing
Authors: van den Hoek P. J. 
Published: December 2007

Abstract
Fluid leak-off in hydraulic fracturing is conventionally described using the well-known linear (Carter) model. Although this works well in low-permeability formations, the linear leak-off assumption may lead to –sometimes significant-overestimation of fracture dimensions in medium to high permeability formations. At present, no methodology is available that allows an easy estimation of the impact of nonlinear fluid leak-off on fracture dimensions and on pressure decline (mini-fracture) analysis. The current paper aims at resolving that deficiency.
An exact numerical solution is presented to the fully transient elliptical fluid flow equation around a propagating hydraulic fracture for arbitrary pump rate(s). In addition, a simple analytical formula for leak-off rate is presented that is shown to yield an excellent approximation of the numerical results, both during fracture growth and after shut-in. This formula can be easily incorporated into any existing hydraulic fracture model, and is applicable over the entire range of fluid leak-off rates, i.e. from low-permeability fracture stimulation on one hand to high-permeability waterflood fracturing on the other hand.
The above result is applied to a variety of hydraulic fracturing field examples to explore the limits of the linear (Carter) leak-off assumption, both in pressure-decline analysis of minifractures and in fracture design. It is, amongst others, shown that in frac-packing and high-perm CRI, the linear leak-off assumption may lead up to a tenfold overestimation of fracture dimensions. This result helps to explain the common field observation that CRI in unconsolidated sandstones results in fractures that appear to be significantly smaller than predicted by conventional hydraulic fracture models.