bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Equations Archie Forgot: Anisotropy of the Rocks
Authors: Haro Carlos F. 
Published: October 2009

Abstract
Archie's empirical equation is extensively used to estimate hydrocarbons in place. This power-laws combination has stood the test of time with little changes. However, it is still poorly understood and considered an ad hoc relation. Our original analysis will prove these laws rigorously, show how they must be amended, and introduce additional accompanying equations. This comprehensive model, which represents the electrical flow through the intricate conductive paths of the rock, is confirmed with Archie's and Hamada's core datasets. It corrects for Archie's inaccuracies.
A thorough appreciation of the pore scale physics behind the modified version of Archie's equation is presented. The principles can be applied in clean and complex formations (shaly-sands, thin beds, vuggy and fractured carbonates) to get enhanced values of water saturation. The theory sheds light on the role and quantification of anisotropy.
Solving for the elaborate pore geometry, we use the Laplace differential equation (not Ohm's law), appropriate in the analysis of electrostatic fields in charge-free regions. Rock morphology dictates its boundary conditions characterized as corner angles. The corresponding particular solution (flow around a corner) and modeling tactic delineate the streamlines throughout the pores. The angles establish strong mathematical links among the exponents of Archie's equation, the geometry of the rock frame and spatial fluid distribution. This quantitative method is lacking in previous saturation models.
The solution constitutes the basis to solve more complicated rock layouts. It enables the calculation of equivalent resistivities (normalized resistances) to take advantage of well-established electrical relationships. The extra equations compute the variable exponents and coefficients of Archie's equation at every depth. They obtain the saturation exponent in clean rocks as function of water saturation, crucial to quality control core electrical data, and to quantify reservoirs under changing saturation (waterflooding). Therefore, improved calculations of original and remaining hydrocarbons are achieved.
New Family of Setting Tools for Ultra Deep and High Temperature Well Condition
Authors: Kessler Calvin , Hill JIm , Shook Eddie , Housden Richard , Collum Eric V. 
Published: October 2009

Abstract
A new generation electro-mechanical downhole power unit for setting and retrieving packers, bridge plugs, whipstocks, subsea tree plugs, and other downhole devices has been recently developed and deployed. The new Downhole Power Unit – Intelligent, DPU-I® is designed to operate at high temperatures and extremely high pressures (400°F, 30K psi) and to provide up to 100K lbf setting force. The high force for either setting or retrieving downhole devices is independent of hydrostatic pressure and provides an alternative to jointed pipe or coiled tubing interventions, which were previously required to obtain high setting forces. New to the industry is the ability to monitor the downhole line tension, stroke length, setting force, the rate at which the force is being applied during the setting operation, and force at which the DPU-I detaches from the downhole device in real time at the wellsite or remotely by means of global satellite communications. This new functionality enables well completions experts to remotely monitor the setting or retrieval operations 24 hours per day, seven days per week. It also provides a record of the setting operation for risk mitigation, and for developing and improving best practices. This new downhole power unit conforms to our digital workflows used to model, measure, and optimize customer assets.
The slow controlled setting operation enables the slips or other anchoring mechanisms in the device to be set and to fully engage the casing/tubing and for the elastomer sealing elements to conform to the casing or tubing ID. This function is extremely critical in highly deviated well conditions and when using casing or tubing with high Rockwell hardness. Unlike setting devices that use explosives, military or governmental escorts are not required. In addition, single lift heli-operations can be used. This tool does not require radio silence operations, and there is no nonproductive time associated with tool redressing between runs. Tool sizes are available for well intervention in 2 3/8 in. tubing through 13 3/8 in. casing and can be tractor-conveyed in high angle or horizontal wells.
Upscaling of Miscible Floods in Heterogeneous Reservoirs Considering Reservoir Mixing
Authors: Garmeh Gholamreza , Johns Russell T. 
Published: October 2009

AbstractInaccurate modeling of reservoir mixing by using large grid blocks in compositional simulation can significantly affect recoveries in miscible gas floods and lead to inaccurate predictions of recovery performance. Reservoir mixing or dispersion is caused by diffusion of particles across streamlines; mixing can be significantly enhanced if the surface area of contact between the reservoir and injected fluid are increased as fluids propagate through the reservoir. A common way to convert geological models into simulation models is to upscale permeabilities based on reservoir heterogeneity. Upscaling affects the degree of mixing that is modeled, but the importance of reservoir mixing in upscaling is largely ignored. This paper shows how to estimate the level of mixing in a reservoir and how to incorporate mixing into the upscaling procedure.We derive the key scaling groups for first-contact miscible (FCM) flow and show how they impact reservoir mixing. We examine only local mixing, not apparent mixing caused by variations in streamline path lengths (convective spreading). Local mixing is important because it affects the strength of the injected fluid, and can cause an otherwise multicontact miscible (MCM) flood to become immiscible. Over 800 2-D numerical simulations are carried out using experimental design to estimate dispersivity as a function of the derived scaling groups.We show that reservoir mixing is enhanced owing to fluid propagation through heterogeneous media. Because mixing is dependent on heterogeneities, upscaling is an iterative process where the level of mixing in both the longitudinal and transverse directions must be matched from the fine to coarse scale. The most important groups that affect mixing are the mobility ratio, dispersion number, correlation lengths, and the Dykstra-Parson's coefficient. Large dispersion numbers yield greater dispersivities away from the injection well. We show through simulations of both FCM and multi-contact miscible (MCM) floods that grid-block size can be significantly increased when reservoir mixing is large. Heterogeneous reservoirs with large longitudinal correlation lengths can be upscaled to larger grid blocks than reservoirs with random permeability fields. This paper shows how to determine a priori the maximum grid-block size allowed in both the x- and z-directions to predict accurately the oil recovery from miscible gas floods.
Lessons Learned While Conducting Drilling and CO2 Injection Operations at the Victor J. Daniel Power Plant in Mississippi
Authors: Koperna George , Riestenberg David , Petrusak Robin , Esposito Richar , Rhudy Dick 
Published: October 2009

Abstract
This paper will discuss the lessons learned from a CO2 pilot injection in southeastern Mississippi, highlighting those issues that are unique to a first-of-its-kind pilot injection at a power plant as well as unexpected results from applying conventional oil and gas technology to tracking CO2 in the subsurface.
Southern Company's Mississippi Power Victor J Daniel, Jr. electric generating facility is hosting a USDOE sponsored CO2 sequestration demonstration as part of the Southeast Carbon Sequestration Regional Partnership. The primary goal of this demonstration is to provide the foundation for safe and secure storage of CO2 in a deep saline reservoir within the confines of a power plant's property boundary.
Major field operations included: (a) collection of baseline data for subsequent monitoring, verification and accounting (MVA); (b) preparing the drill site; (c) drilling and completing the CO2 injection and observation wells, (d) characterizing the reservoir using core analyses, (e) baseline geophysical well logging and seismic surveying operations, (f) injecting more than 3,000 tons of CO2, (g) post-injection time-lapse geophysical well logging and seismic surveying operations, and (h) site closure. During the execution of these operations, additional activities unique to operations on the plant property included: (a) site access agreements and restrictions, (b) site preparation, (c) site reclamation, (d) advanced notification of field activities, and (e) operational monitoring.
With regard to the application of conventional oil and gas protocols to a sequestration pilot, there were several unexpected results, including those obtained by geophysical logging, seismic surveys, and wellhead and bottomhole pressure data acquisition.
Determination of Petrophysical Parameters and Mud Filtrate Invasion Profile Using Joint Inversion of Induction Logging and Pressure Transient Measurements
Authors: Liang Lin , Abubakar Aria , Habashy Tarek 
Published: October 2009

Abstract
Induction logging technique is one of the important tools for determining the formation resistivity of the subsurface. The near-wellbore formation resistivity is usually affected by the invasion of water-based mud-filtrate. The flushed-zone resistivity (Rxo), the undisturbed-zone resistivity (Rt) and the diameter of invasion (Di) can be estimated from the interpretation of array induction logging measurements through a model-based inversion process. Conventionally, the inversion assumes a layer-cake formation with three-parameter invasion model or with a four-parameter invasion model that incorporates a ramped transition zone.
In this study, we introduce a 2.5D inversion approach for interpreting the induction logging data. The inversion is constrained by using a multiphase fluid-flow model which simulates the mud-filtrate invasion process and calculates the spatial distribution of the water saturation and salt concentration, which are in turn transformed into the formation conductivity using a resistivity-saturation formula. In this way, the inverted invasion profile is consistent with the fluid flow physics. Jointly with the pressure data, the inversion estimates a parametric one-dimensional distribution of permeability and porosity.
Previous works either assumed that the mud-cake permeability is known and used the bottom-hole pressure as a boundary condition, or alternatively used an invasion model to calculate the dynamic invasion rate as a boundary condition to the fluid-flow simulator at the wellbore sandface. The dynamic invasion process is complicated and is affected by many factors. Hence, although possible, it is difficult to calculate the invasion rate. This study shows that it is possible to directly invert the mud-filtrate invasion volume from the fluid-flow-constrained inversion of the induction logging data. Moreover, this approach is not limited by the traditional interpretation of the formation test, which is based on a single phase model without taking into account invasion. The joint inversion of the induction logging and pressure data demonstrates the ability to provide a more reliable interpretation of formation permeability. The advantage of the approach presented here, is its possible generalization to three-dimensional geometries, for example dipping beds and highly deviated wells.
The Chiswick Field: Long Horizontal Wells and Innovative Fracturing Solutions in a Low Permeability, Sandstone, Gas Reservoir in the North Sea
Authors: Coghlan G. , Holland B. 
Published: October 2009

Abstract
In order to obtain commercial flow rates from the Chiswick field, a low permeability gas reservoir in the UK Southern Gas Basin, it was apparent that field development needed horizontal wells with multiple, propped hydraulic fractures. While this completion strategy is commonplace in US onshore tight gas and a few North Sea chalk reservoirs, only a handful of such completions were attempted historically in the sandstone reservoirs of the North Sea. Ongoing success in chalk and in deep sandstone reservoirs onshore Germany raised expectations that, using modern practises and materials, the strategy could be successfully executed in the high cost environment of offshore UKCS.
Chiswick lies in 42m of water at the UK-Netherlands median line. Gas is located in alluvial channel sand systems of Carboniferous age. The reservoir is at 3300m TVDSS with average porosity of 10% and permeability 1 mD; initial pressure and temperature are 392 bara, 115°C respectively. Results from four appraisal wells, drilled 1984 -1999, determined that commercial rates would only be possible if development wells were horizontal and hydraulically fractured. The initial field development plan entailed two horizontal wells with 2km reservoir sections, stimulated with several massive propped fractures.
The complex reservoir is highly stratified with intermixed channel sands, coal and shale. Besides reservoir uncertainties, there were operational challenges to be overcome. A major hurdle was a constrained regional market for high-specification stimulation vessels for the Chiswick development programme. A solution was found by converting a large supply-vessel into a stimulation vessel with the installation of a large capacity, land-based frac-spread. It successfully delivered fourteen frac-jobs in three wells (two are described in this paper). Target post-stimulation flow-rates were achieved in all cases.
The paper discusses how a fundamental rethink of what was technically possible allowed a complex tight gas field in the North Sea, previously thought non-commercial, to be brought successfully onto production.
Predicting Dynamic Barite Sag in Newtonian Oil Based Drilling Fluids
Authors: Nguyen T. C. , Miska S. , Yu M. , Takach N. 
Published: October 2009

AbstractBarite Sag is the settling of barite particles (or other weighting materials), which results in the undesirable fluctuations in drilling fluid density. A variety of major drilling problems including lost circulation, well control difficulties, poor cement jobs and stuck pipe can result from uncontrolled barite sag. Study of this phenomenon and how to mitigate its effects has long been of interest.This paper describes a fundamental mathematical approach to analyze the settling of barite particles in shear flow of Newtonian fluids. A set of four coupled partial differential equations to describe dynamic barite sag in Newtonian fluids in pipe flow is obtained by applying mass and momentum conservation for solid and liquid phase. Solid concentration in axial and radial directions as a function of time is calculated by using an explicit numerical method to solve these equations. A number of experiments in a flow loop were conducted to verify the mathematical model.A method proposed by Bern et. al.4,8 to measure the fluid density during circulation was modified to measure the change of circulating density in the test section. Two mass flow meters were installed at the inlet and outlet of the flow loop's test section. Differences in the density measurements over time were converted to the solid accumulation, which was compared with results from the modeling. In addition, based on the experimental results, three different stages of barite accumulation due to the settling and bed pickup of barite particles during circulation will be presented. The proposed methodology and results of this study will help drillers have a better understanding in terms of undesirable density fluctuations and barite bed characteristics.
The Art and Practice of Acid Placement and Diversion: History, Present State and Future
Authors: Kalfayan L. J. , Martin A. N. 
Published: October 2009

Abstract
With the increasing need for highly cost-effective well production enhancement applications, acid stimulation is becoming increasingly popular. To be successful, acidizing procedures require distribution of stimulation fluids across and within the desired treatment interval. Historically, this has been approached with mechanical placement or chemical diversion of treatment fluids. Method selection can be crucial to treatment success – and an increasing number of options exist – each with its own set of limitations and uncertainties. Preferences and success vary for matrix and fracture acidizing – in vertical and deviated wellbores, in sandstones and carbonates and in cased and perforated, gravel packed, and openhole completions. Method selection and implementation can be daunting but greatly rewarding – calling for creativity and field experimentation.
This paper focuses on the important role of acid placement and diversion, and the types, purposes, benefits and pitfalls of the methods currently in practice. The importance of treatment placement was evident and recognized in the earliest acid treatments conducted in the late 19th century. Although this need has been recognized since the dawn of acidizing, at no point in its history has a diversion method found universal reliability and acceptance. Insufficient interval coverage is perhaps still the most common reason why acid jobs often fail to meet expectations. A well-conceived treatment in all other aspects of design (damage assessment, selection of fluids and additives, and volumes) can count for nothing if the treatment does not enter or cover those portions of the interval with the greatest need of stimulation.
Since the first commercial acid treatments in the 1930s, mechanical placement has evolved from crude rubber "packers" to advanced coiled tubing technologies. Chemical and particulate diverters have evolved from chicken feed to specialized chemical systems, including self-diverting fluids. With chemical diversion, different methods have come into and fallen out of favor – replaced by new ideas, or those forgotten and subsequently revived.
Within its historical perspective, this paper discusses present-day acid placement and diversion methods, their best applications and their limitations – with a view and emphasis on industry needs and direction for the future.
Enhanced Natural Gas and Condensate Recovery by Injection of Pure SCCO2, Pure CH4 and Their Mixtures: Experimental Investigation
Authors: Al-Abri Abdullah , Sidiq Hiwa , Amin Robert 
Published: October 2009

Abstract
This paper quantitatively investigates the fractional condensate recovery and relative permeability following supercritical carbon dioxide (SCCO2) injection, methane injection and the injection of their mixtures; and compositionally-sensitive reservoir gas relative permeability following SCCO2 injection. A high pressure high temperature experimental laboratory was established to simulate reservoir conditions and to perform relative permeability measurements on sandstone cores. All tests were made at measured miscible conditions of 5900psi, 95-160°C and constant flow velocity inside the cores of 10cm/h. Two sequences of coreflooding experiments were employed to replicate the displacement of reservoir gas by pure SCCO2 injection, and the displacement of condensate by injection of different SCCO2-methane concentrations. This work is part of an integrated enhanced gas and condensate recovery project conducted for a local reservoir in Western Australia.
The results provide valuable insights into gas and condensate recovery following SCCO2 injection with various methane impurities. The results demonstrate that SCCO2 injection appears to offer less capillary instabilities and better mobility ratios resulting in a delayed breakthrough and favorable condensate sweep efficiency (79% recovery and 0.62 PV BT); as opposed to the injection of SCCO2-methane mixtures, or pure methane injection (45% recovery and 0.27 PV BT). Further, the relative permeability curves to condensate improve following SCCO2 injection due to decrease in condensate-to-gas viscosity ratio (curves cross at 58% gas saturation with SCCO2 injection compared to 24% gas saturation with methane injection). On the gas-gas side, experiments confirm that the greater the methane concentration in the reservoir gas (i.e. less CO2 contamination) the better relative permeability and sweep efficiency data become at the flooding temperatures and pressures (curves cross at 40% SCCO2 saturation when 90% methane is present in the reservoir compared to less than 5% SCCO2 saturation when only 25% methane is present in the porous medium).
These data will help the operators develop operational and design strategies for their current and future EOR projects, as well as to input parameters for full-field simulation practices.
Well Treatment Fluids Prepared with Oilfield Produced Water
Authors: Li Leiming , Eliseeva Ksenia , Eliseev Vasily , Bustos Oscar A. , England Kevin , Howard Paul R. , Boney Curtis L. , Parris Michael D. , Ali Syed A. 
Published: October 2009

Abstract
Oilfield produced water usually comprises both the formation water and injected fluids from prior treatments. Produced water may be environmentally hazardous and usually contains bacteria, hydrocarbons, and high levels of dissolved salts. As such, the proper disposal of produced water is often expensive. Meanwhile, fresh water used to formulate oilfield treatment fluids is becoming more costly and more difficult to obtain. Operators, as well as service companies, have therefore shown a strong desire to use produced water in field operations to reduce costs. Consequently, a series of laboratory experiments have been performed to optimize the viscosity profile of fracturing fluids prepared with produced water. Preparation of polysaccharide-based fracturing fluids with produced water frequently resulted in fluids with poor viscosity profiles despite the fact that the produced water was pretreated with biocide. Furthermore, the problem could not be resolved by just adding more biocide. In a number of representative cases, the guar-based fracturing fluids, prepared with produced water and regular biocide, quickly lost their viscosity after hydration, possibly because of the degradation of the guar by the bacterial enzymes in the produced water. A new fluid stabilizer was recently invented to address the problem, and it was observed that the addition of the stabilizer dramatically extended the lifetime of the polysaccharide-based fracturing fluids prepared with produced water.
The fluid stabilizer was simply added to produced water prior to mixing the polymer. The polysaccharide-based fluids prepared with the stabilizer-treated produced water showed stable viscosity profiles at both surface and bottomhole temperatures.
The use of the fluid stabilizer has greatly enhanced the fluid performance and job efficiency since its initial introduction in the field in June 2008 and was implemented in about 80 successful fracturing and sand control jobs by the end of 2008.
The invention and successful application of the fluid stabilizer have reduced the operating costs for the operators and service companies. At the same time, this new technology has also helped improve the environment by cutting the fresh water usage in the field. This paper will discuss the chemistry, experimental studies, and case histories.