bluuebunny/crossref_metadata_2025_split huggingface dataset:
Advances in Single-Diameter Well Technology: The Next Step to Cost-Effective Optimization
Authors: Waddell Kevin 
Published: December 2007

Abstract
From inception, solid expandable tubular technology has been touted as a game-changing technology. The logical end result of the technology, a single-diameter well, consists of a casing string with the same diameter at the top of the well as at total depth (TD). However, many drilling operators were reluctant to embrace even the basic solid expandable tubular concept without any track record, coupled with what they saw as the inherent risks.
Now, after five years of commercial installations, solid expandable tubular technology has proven to be a viable and economically feasible alternative to conventional drilling technology. In the majority of these installations, solid expandable tubulars have been deployed as a contingency to save a well when conventional technology failed. While this type of application is appropriate, operators do not reap the full advantage of all the benefits solid expandable tubular technology offers when integrated as part of the well plan.
A crucial step in the acceptance of expandable tubulars as a viable well construction method is to plan the system into the initial well design. In order for the tubulars to be planned into the original well design, operators must understand the compelling economic business cases for the application as well as accept the level of risk. The proven track record has helped mitigate the risk level for many operators, who are now focusing on the value proposition this technology provides. Operators must be comfortable with solid expandable technology in order to make the necessary leap of faith to the single-diameter well.
This paper will present the progress of monobore technology up to the present. It will discuss the stages achieved and those that still must be overcome to make this technology feasible. The paper will demonstrate that with solid expandable tubular and monobore technology, operators in general and deepwater operators in particular, will be able to maximize reservoir potential and lower drilling costs when using this value-added technology.
Modern Concepts in Perforation Inflow Diagnostic (PID) Testing: A Safe, Green, and Cost-Effective Technique for Evaluating Pre-Frac Reservoir Parameters
Authors: Hawkes Robert V. , Hategan Florin 
Published: December 2007

Abstract
Conventional completions and testing methods of low permeability gas reservoirs involve the cost and logistics of balanced and underbalanced perforating, next day stimulation treatment, surface production equipment, and the need for flaring during clean-up operations. In Canada, due to government regulations, operators will conduct the buildup test immediately after one or two day of clean-up operation. This practice has resulted in post-frac welltest analysis being masked by fracture fluid still present in the proppant pack and formation, resulting in misleading estimates of reservoir and fracture parameters important for production forecasting and completion evaluation.
Perforation Inflow Diagnostic, referred as PID testing, is a modern testing technique designed to deliver in a cost-effective manner valuable reservoir information such as: reservoir pressure, formation flow capacity, unstimulated gas inflow rate potential and near wellbore damage conditions prior to the fracture treatment. The advantages of PID testing are numerous: capability of accurate measurement of very low gas rates in low permeability (tight) gas wells (often reported as too small to measure), provides a safe testing environment, ensures secrecy and it defines itself as a green well testing procedure since it does not require flaring or venting of natural gas. PID testing is simply the surface and/or subsurface monitoring of the pressure response following extreme underbalanced perforating conditions, using electronic pressure recorders capable of high sampling rate. Unlike conventional testing procedures, the surface valve is closed during the entire test period and the formation fluids are produced into the closed chamber (casing and/or tubing volume). The measured pressures are converted to corresponding gas rates, based on the well-established closed chamber theory. PID testing therefore allows the collection of pressure and rate data required to derive the in-situ matrix permeability, wellbore skin and reservoir pressure.
Well-Completion Techniques and Methodologies for Maintaining Underbalanced Conditions Throughout Initial and Subsequent Well Interventions
Authors: Cavender Travis W. , Restarick Henry L. 
Published: December 2007

AbstractUnderbalanced drilling (UBD) is undoubtedly one of the "hottest" topics in the oilfield today. Although not a new concept, UBD has just recently come of age, as the benefits it offers to the oil and gas industry have been noted only within the last few years. Underbalanced drilling offers many notable advantages, which include: Reducing formation damageIncreasing the rate of penetration (ROP) and bit life.Allowing the reservoir to be tested and evaluated while drilling.Reducing the number of trips into the holeMinimizing differential sticking of pipeLimiting lost circulationFacilitating early production while drillingAccessing depleted or low-pressure reservoirsSelecting TD from inflow performance.The benefits of the above are obvious; therefore, they will not be discussed in depth in this paper.While UBD technology has come a long way since the early wells that were brought in via gushers that rose above the wooden derricks, underbalanced drilling can only supply &lt;i&gt;part&lt;/i&gt; of the solution – once drilling procedures are concluded, and the completion phase begins; the primary operational drivers change. Rather than focusing on such activities as drilling performance and formation evaluation while drilling, the completion drivers target the &lt;i&gt;reduction of fluid loss&lt;/i&gt; and the &lt;i&gt;elimination of formation damage&lt;/i&gt;. Thus, attaining a total solution requires that underbalanced conditions not only are maintained during the completion and for the life of the well, but also throughout any future well interventions. Unfortunately, the advances in underbalanced completion technology have lagged behind those seen in underbalanced drilling.This paper will explore the strategies, techniques and tool systems required 1) to maintain an underbalanced condition throughout the initial well completion phase and during all future remedial operations, and 2), to create a cost-effective solution that will enhance and accelerate maximum reservoir drainage.To this end, if underbalanced technology is approached as a production enhancement technique that starts at the initial stage of drilling the well and continues throughout the life of the well, the end result will be that the value of the reservoir will be increased, and will be collected within in a shorter period of time.
Design, Interpretation, and Assessment of Short-Term Pressure-Transient Tests
Authors: Soliman M. Y. , Azari M. , Ansah J. , Kabir C. S. 
Published: December 2007

Abstract
In order to meet most test objectives, conventional transient well testing usually requires long flow and shut-in periods. However, the current industry drivers demand short, cost-effective, and environmentally friendly test procedures, especially in exploration wells. This is particularly true in deepwater and arctic environments where conventional tests may be prohibitively expensive or logistically not feasible.
While various short-term tests, test procedures, and interpretation methods are available for conducting successful short-term tests, clarity is lacking for specific applications of these methods. Some of these tests include surge testing, closed-chamber testing, slug testing, underbalanced perforating and testing, and back-surge perforation cleaning. This paper provides comprehensive evaluation of general closed-chamber tests, including general surge tests, and their comparison with special tests such as, FasTest,™ Impulse™ test, and slug tests. For each of these techniques, the review will examine: Test design, testing procedureTheoretical background of each of these techniquesMethod of data analysis including comparison based on both theoretical and practical considerations to determine the expected reliability, accuracy, and ease of analysis.
A large portion of the paper will be devoted to field examples. Several actual case studies are analyzed using the various techniques, and results are tabulated and presented. The analyses of several of these examples will be presented in significantly more detail to compare techniques available to analyze the well-testing data obtained from surge testing, closed-chamber DST, slug testing of oil wells, underbalanced perforating and testing, and back-surge perforation cleaning.
Updated United Nations Framework Classification for Reserves and Resources of Extractive Industries
Authors: Ahlbrandt Thomas S. , Blaise Jean René , Blystad Per , Kelter Dietmar , Gabrielyants Gregorio , Heiberg Sigurd , Martinéz Anibal , Ross James G. , Slavov Slav , Subelj Andrei , Young Elliott D. 
Published: December 2007

Abstract
The United Nations have studied how the oil and gas resource classification developed jointly by the SPE, the World Petroleum Congress (WPC) and the American Association of Petroleum Geologists (AAPG) could be harmonized with the United Nations Framework Classification (UNFC) for Solid Fuel and Mineral Resources (1).
The United Nations has continued to build on this and other works, with support from many relevant international organizations, with the objective of updating the UNFC to apply to the extractive industries. The result is the United Nations Framework Classification for Energy and Mineral Resources (2) that this paper will present.
Reserves and resources are categorized with respect to three sets of criteria: Economic and commercial viabilityField project status and feasibilityThe level of geologic knowledge
The field project status criteria are readily recognized as the ones highlighted in the SPE/WPC/AAPG classification system of 2000. The geologic criteria absorb the rich traditions that form the primary basis for the Russian classification system, and the ones used to delimit, in part, proved reserves. Economic and commercial criteria facilitate the use of the classification in general, and reflect the commercial considerations used to delimit proved reserves in particular.
The classification system will help to develop a common understanding of reserves and resources for all the extractive industries and will assist: International and national resources management to secure supplies;Industries&#39; management of business processes to achieve efficiency in exploration and production; andAn appropriate basis for documenting the value of reserves and resources in financial statements.
Use of Stripping Ratios to Identify Dispersion Levels and Displacement Mechanisms in Miscible Gas Floods
Authors: Parakh Harshad , Johns Russell T. 
Published: December 2007

Abstract
Oil recovery estimated from numerical simulation of miscible gas floods is highly dependent on the grid-block sizes used and the level of reservoir dispersion. Stripping ratios, defined as the ratio of certain heavy to light components, have been used recently to estimate the level of in situ dispersion at the field scale. The use of stripping ratios, however, has not been thoroughly investigated.
The focus of this paper is to validate the use of stripping ratios and to determine its appropriate definition for certain gas injection processes. The approach is applied to the condensing/vaporizing displacement of twelve-component oil by a five-component miscible injectant (MI). Analytical gas injection theory based on the method of characteristics is used to help identify the correct choice of components to calculate the stripping ratio. Numerical simulations are conducted for both 1-D and 2-D gas floods.
The results from 1-D displacements show that the condensing and vaporizing region can be identified from stripping ratios when the stripping ratio is calculated from the heaviest component in the oil and the lightest component in the oil not present in the injected gas. The stripping ratio for 1-D field scale displacements is shown to be useful in identifying (as measured from core data) if a large level of dispersion and mixing is present for such reservoirs. For more realistic 2-D (and 3-D) displacements, however, crossflow or re-saturation occurs, which can complicate the interpretation of the stripping ratio and its use as a practical reservoir engineering tool. We show that the level of dispersion at field scale might be qualitatively confirmed by comparison of stripping ratio and oil saturation data from cores to those determined from simulation. When dispersion is low (near a longitudinal dispersivity of about 1.0 ft) resaturated regions give large oil saturations accompanied by very large stripping ratios. These features are not present at dispersivity levels greater than 5.0 ft.
Rotary Sidewall Cores- A Cost Effective Means of Determining Young's Modulus
Authors: Britt Larry K. , Smith Michael B. , Haddad Ziad , Reese Jennifer , Kelly Patrick 
Published: December 2007

Abstract
The objective of hydraulic fracturing is to design and execute a fracture stimulation treatment that achieves the desired fracture dimensions (length and conductivity) to maximize a wells production rate and reserve recovery. To achieve this objective, there are several critical parameters to the process, and these fall into two distinct categories: 1) parameters over which we have little control, but need to understand, and 2) those that we control, but have lesser impact on the process. The first category includes fracture height, fluid loss coefficient, tip effects, and Young&#39;s modulus. The second category includes pump rate and fluid viscosity. Of the former parameters, Young&#39;s Modulus is the only variable that can be measured, in advance, via lab tests.
Traditionally, Young&#39;s Modulus is measured through stress-strain testing of geologic samples (core plugs) which always demanded an L/d (Length/ diameter) ration of at least 2:1. The reason for this criterion is that the ultimate failure mechanism for most rocks under compression loads is the formation of a shear fracture. For most rock types, this shear fracture will form at an angle of about 30° from the axis of the maximum compression load. Thus, a 2:1 L/d ratio allows a through-going shear fracture to form for a failure angle of 30°. For stress-strain testing NOT concerned with ultimate failure of the sample, this valid criterion has always been followed - arbitrarily and artificially. Unfortunately, this sample criterion generally eliminates the use of sidewall cores.
This paper details and documents an evaluation of the Length to diameter criteria through finite element modeling, tri-axial compression testing of aluminum, and compression testing of actual sedimentary rock samples. Through this work, it is evident that core samples of L/d significantly less than 2:1 can provide reliable values of static Young&#39;s Modulus. Further, these results indicate that rotary sidewall cores can be utilized to determine Young&#39;s Modulus in many applications provided adequate sample quality assurance is undertaken to ensure sample integrity.
Simulation of Miscible Flow Including Bypassed Oil and Dispersion Control
Authors: Coats K. H. , Thomas L. K. , Pierson R. G. 
Published: December 2007

Abstract
This paper describes methods for the simulation of first contact miscible, multi-contact miscible and vaporizing gas drive, which include logic to account for bypassed oil. Dispersion control is included for first contact miscible, FCM, cases.
First contact miscibility may be simulated in fully compositional mode or in pseudo two-component EOS mode. Pseudoization is performed internally in the model so that hydrocarbon fluid density and viscosity, as functions of pressure and composition, are the same as calculated in NC-component mode. Bypassed oil and dispersion control are based on an extension of Koval's method. This procedure allows the user to adjust the fractional flow of oil during upscaling or history matching to match fine grid or historical results. This feature can be used to simulate both WAG and tertiary recovery projects where solvent injection is preceded by a water injection period.
Example cases are included to illustrate the techniques presented in this paper. Results are also given on the efficiencies of the algorithms.
Improved Pore-Pressure Prediction and Mechanical Earth Model Estimation Through Binary Decomposition of Seismic Inversion Data in Subresolution Clastic Sequences
Authors: Engelmark Folke 
Published: December 2007

Abstract
Formation pore pressures that exceed the hydrostatic gradient are common in all basins worldwide. The most common cause is undercompaction, which occurs when the rate of shale sedimentation is high, thus preventing water to escape from the pore space in the underlying sediments. This leads, in turn, to a redistribution of the overburden stress, i.e., part of the overburden stress is maintained by the pore fluids and the effective stress on the rock fabric decreases by an equal amount. Porosity is preserved and assumed to be in balance with the effective stress. Other mechanisms that can generate increased pore pressure include: dewatering of clays, generation of hydrocarbons, cracking of oil to gas under increasing temperature, and volumetric increase of the fluids when temperature is increasing.
Uncertainty in the pore-pressure profile along the planned drilling path means, at the very least, increased cost to cover contingency plans, but can also include very expensive mitigation work, especially in deep- and ultra-deepwater environments. Worst-case scenarios can include loss of the well, loss of lives, and severe environmental impact.
Current state-of-the-art methods for pore-pressure prediction include classification of lithology and pore fluids based on prestack inverted data yielding compressional and shear velocities as well as density. This allows the rock physics equations to be customized for improved accuracy in the predicted pore pressure.
Clastic basins consist predominantly of interbedded shales and sands. The vertical resolution of seismic data depends on the wavelength of the propagating seismic energy, but typical resolution in Tertiary basins is about 30 ft, which means the extracted elastic parameters often represent a net to gross (N/G) rather than the properties of individual sands and shales. The volumetric content of each lithology can be evaluated from the elastic parameters extracted from the seismic data. However, when there are hydrocarbons present, especially gas, the estimate of N/G and the elastic properties of the two lithologies are more difficult to evaluate.
In this paper, we take the inversion process one step further by decomposing the seismic elastic data into the individual properties of the sands and shales. In addition to improving the accuracy of the pore-pressure prediction and the mechanical properties of the two lithologies, we also get an estimate of N/G, hydrocarbon properties, and saturation in the sands. The ability to estimate elastic properties for sands and shales individually is also very important to get correct estimates of the mechanical rock properties.
Insitu Characterization of Formation Fluid Samples - Case Studies
Authors: Elshahawi H. , Hashem M. , Dong C. , Hegeman P. , Mullins O. C. , Fujisawa G. , Betancourt S. 
Published: December 2007

Abstract
Sampling in the early stages of the exploration and development cycle is essential to provide key information for field planning and facilities design. In the majority of deepwater and other high cost wells drilled these days, formation tester samples may be the only source of fluid properties reliable enough to be used for economic screening. It is therefore critical to collect representative high quality samples early in any exploration or appraisal campaign. With the aid of real time insitu fluid characterization, sample quality can be assured, and the sampling process can be optimized. Insitu fluid characterization is essential for making decisions about where and when to sample, and how many samples to acquire. In that manner, maximum quality information may be acquired in an optimal amount of time. This is particularly critical in offshore deepwater sampling jobs, where rig rates can reach hundreds of thousands of dollars per day.
This paper describes how the latest techniques for downhole fluid characterization can be put to maximum use. These techniques include real time composition measurement, fluid type identification and single-phase assurance. The absorption properties of hydrocarbons in Near-Infrared spectroscopy and principal component analysis techniques are used to obtain real time composition. This includes carbon dioxide concentration, Gas-Oil-Ratio, and water volume fraction as well as the relative abundance of three broad reservoir fluid pseudo-components. Fluid type identification and single-phase assurance are achieved with downhole gas detection and fluorescence measurements. Fluorescence monitoring enables the detection of condensate formation if the dew point pressure of a wet or retrograde gas system is crossed during sampling. In some cases, it also provides a means of qualitatively distinguishing between gas, condensate, light oil, and heavy oil from oil-base-mud filtrate.
Several case studies are presented here to demonstrate the techniques of composition measurement, fluid type identification, and single-phase assurance. The case studies clearly show how these techniques help obtain high quality sample in an optimal amount of time.
Dynamic Simulations With an Improved Model for Foam Generation
Authors: Kam S. I. , Nguyen Q. P. , Li Q. , Rossen W. R. 
Published: December 2007

Abstract
We present the first 1D simulations of dynamic foam displacements with a new population-balance model incorporating bubble creation controlled by pressure gradient. For the first time, a population-balance model is fit to steady-state experimental data for both the three foam states (coarse foam, intermediate state, and strong foam) and the two strong-foam regimes (low-quality and high-quality) observed in laboratory studies. Simulations confirm the stability of the coarse-foam and strong-foam states to small perturbations, and the instability of the intermediate state.
In dynamic displacements, the model shows foam generation as injection rates increase, or as liquid fraction of injected fluids increases, in agreement with laboratory observations.
When coarse foam is created instead of strong foam, there is a narrow region of finer foam predicted near the gas displacement front. This region appears to play a role in foam generation. However, in the cases examined, foam generation occurs at roughly the same injection rate as predicted by local-steady-state theory. Because of this narrow region of finer-textured foam, fronts can be sharper than estimated from fractional-flow theory assuming a constant gas viscosity at its steady-state value behind the displacement front.
If a strong foam forms in the low-quality-regime, the kinetics of foam generation and destruction affect the length of the entrance region in which foam forms. Therefore, the length of the entrance region can be used to calibrate the kinetic parameters in the model. The displacement front and the bank behind it, however, are essentially what one would have predicted from local-steady-state modeling. The complexities of population-balance modeling are not necessary, if it is known that strong foam will be created.