bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Comparative Study of Mechanical Properties of Density-Reduced Cement Compositions
Authors: Ravi Kris , McMechan David E. , Reddy B. R. , Crook Ron 
Published: June 2007

Summary
This paper discusses the tests conducted to determine the mechanical properties and the integrity of the cement sheath when subjected to cyclic loads. In addition, the effects of well operation on cement sheaths of different mechanical properties are analyzed, and the results are discussed. The results clearly demonstrate the importance of both laboratory measurements of cement-sheath mechanical properties and engineering analysis of the effect of well operations on the integrity of the cement sheath.
Lower-density cement systems are discussed in this paper, along with how the density was lowered by incorporating conventional additives such as
Pozzolanic beads (cenospheres) Hollow glass beads Gas bubbles Water-binding additives Silica fume Fly ash
Primary cementing compositions for oilwell applications are becoming increasingly complex and challenging because of the extreme well operating conditions encountered. The stresses exerted on the cement sheath during well operations could be severe enough to damage the cement sheath and negatively affect the safety and the economics of the well.
The results discussed in this paper should help operators design a cement sheath that can withstand the stresses from well operations, thus improving the safety and economics of the wells.
Effect of IFT Variation and Wettability on Three-Phase Relative Permeability
Authors: Cinar Y. , Marquez S. , Orr F. M. 
Published: June 2007

Summary
In this paper, we report experimental results that demonstrate the combined effects of variations in interfacial tension (IFT) between one pair of three phases and wettability of a porous medium on three-phase relative permeabilities. We used two analog three-phase systems, in which the IFT between two of the phases could be varied systematically while holding the IFTs between the other pairs of phases approximately constant. We report measured three-phase relative permeabilities for systems with IFTs between two of the three phases varying from 0.005 to 2 mN/m. Phase-recovery and pressure-drop data were interpreted by the combined Welge/ Johnson-Bossler-Naumann (JBN) method to yield relative permeability curves. The results obtained indicate that as IFT between the analog gas/oil pair of phases decreases, relative permeabilities for those phases increase at a given saturation. The relative permeability for the analog water phase remains nearly unchanged for water-wet porous systems, but it decreases especially at low phase saturations for oil-wet porous systems.
Spatial Error and Convergence in Streamline Simulation
Authors: Jimenez Eduardo , Sabir Kamran , Datta-Gupta Akhil , King Michael J. 
Published: June 2007

Summary
Streamline models are routinely used for waterflood optimization and management and are being extended to more complex processes (e.g., compositional simulation). Despite these new developments, no systematic study has examined the underlying numerical spatial and temporal discretization errors in streamline simulation and their convergence. Such studies are a prerequisite to determining the optimal density of streamlines during simulation and ensuring the resulting accuracy of the solution.
In this paper, we first examine transverse spatial errors (e.g., errors resulting from the number or placement of streamlines). We provide an analytic proof and a numeric demonstration of the order of spatial convergence of the mass-balance discretization error. Both global and local calculations are performed, and they demonstrate the impact of stagnation regions on the order of convergence. A second transverse error arises for faulted grids, where lack of flux continuity at cell faces can lead to incorrect trajectories. These trajectory errors are of zeroth order and can be resolved only by introducing additional degrees of freedom into the streamline velocity model. Longitudinal spatial errors also arise and are associated with the inaccurate calculation of time of flight across cells.
We show that the commonly used algorithm for corner-point cells leads to inaccurate time-of-flight calculations for stratigraphic grids, depending upon aspect ratio. We provide a simple and exact means of calculating the time of flight for arbitrary corner-point cells, or unstructured grids, in two or three dimensions, for either compressible or incompressible flow. Finally, using this new time-of-flight formulation, we analyze a series of cross-sectional finite-difference simulations to identify grid-orientation errors in the numerical calculation of flux and spatial error.
Real-Time Downhole pH Measurement Using Optical Spectroscopy
Authors: Raghuraman B. , O'Keefe M. , Eriksen K. O. , Tau L. A. , Vikane O. , Gustavson G. , Indo K. 
Published: June 2007

Summary
A new downhole pH sensor has been developed to provide an in-situ pH measurement of formation water at reservoir conditions, and results are presented for two wells in the Norwegian Sea. The measurement technique, for use with wireline formation-sampling tools, uses pH-sensitive dyes that change color according to the pH of the formation water. To make a real-time pH measurement, the dye is injected into the formation fluid being pumped through the tool flowline, and the relevant visible wavelengths in an optical detector are used to record the dye signal and calculate pH with 0.1-unit accuracy.
The pH of a formation fluid alters as the sample is brought to surface from the high-temperature and high-pressure conditions downhole, owing to acid gases and salts coming out of solution and changes in water-chemistry equilibria. To obtain an accurate pH, the measurement must be made downhole at reservoir conditions. Unlike potentiometric methods in which fouling of electrode surfaces by oil and mud is a potential problem, the dye technique is robust because the dye is isolated from the formation fluid and is injected into the sample only when a measurement is made. The technique has been applied successfully to both oil-based and water-based drilling muds, with successful measurements even in mixed oil/water flows. Multiple measurements of pH at a single sampling station demonstrate that the method is robust and repeatable. These measurements have been compared with numerical simulations using a multiphase chemical-equilibrium model that uses laboratory analysis of collected water samples as input.
pH is a key parameter in water chemistry and is critical for corrosion and scale studies. Accurate downhole pH measurement allows a more-accurate selection of appropriate completion materials and more-effective planning for scale treatment and inhibition.
Development, Verification, and Improvement of a Sediment-Toxicity Test for Regulatory Compliance
Authors: Dorn P. B. , Rabke S. , Glickman A. , Nguyen K. , MacGregor R. , Candler J. , Wong D. C. L. , Hood C. , Hall J. , Purcell T. 
Published: June 2007

Summary
The offshore oil and gas industry has moved toward the use of synthetic-based drilling fluids (SBFs), changing potential exposure scenarios for discharged cuttings when compared to those of water-based drilling fluids (WBFs). Unlike WBFs, SBFs sorb predominately to particles in the cuttings and are not dispersed extensively into the water column; therefore, a sediment-toxicity test was required by the US Environmental Protection Agency (EPA) in addition to the existing water-column test to define a bestavailable-technology (BAT) limit. Inclusion of a sediment-toxicity test for National Pollutant Discharge Elimination System (NPDES) compliance was precedent-setting and unique. To fulfill the US EPA requirements, an interindustry research group worked with the EPA to develop a suitable test that met the technology-based discharge standard. Toxicity of discharged field drilling fluid is compared to a reference SBF (C16–C18 internal olefin), and, for compliance, the ratio of the reference-drilling-fluid median lethal concentration (LC50) to the field-mud LC50 must be ≤1.0. Before the use of this test, there were concerns that false positive results could lead to incorrectly identified noncompliance events, limiting the use of SBF technology. Consequently, initial application allowed the use of a variability factor (K-factor) in determining the ratio. After use of the compliance test was initiated, research was continued to reduce test variability and minimize false positives. This research included (1) analysis of NPDES-compliance data (500+tests), (2) two interlaboratory testing programs, (3) analysis of reference-fluid data from one commercial laboratory, and (4) refinements to test sediment type and effects on animal health. The results of these efforts to date are reviewed in this paper and are used to identify potential improvements in the application of the test as a regulatory tool.
The Power of Real-Time Monitoring and Interpretation in Wireline Formation Testing—Case Studies
Authors: Elshahawi H. , Hashem M. , McKinney D. , Ardila M. , Ayan C. 
Published: June 2007

Summary
Modern wireline formation testers (WFTs) are able to collect a massive amount of data at multiple depths, thus helping to quantify changes in rock and fluid properties along the wellbore, to define hydraulic flow units, and to understand the reservoir architecture. They are being used routinely in a wide range of applications spanning pressure and mobility profiling vs. depth, fluid sampling, downhole fluid analysis (DFA), interval pressure-transient testing (IPTT), and microfracturing. Because of the complex tool strings and the elaborate operational aspects involved in wireline formation testing, success requires detailed upfront planning and procedural design as well as real-time operational and interpretational support.
It is becoming increasingly critical for operating and service company experts to remotely monitor and interpret WFT surveys in real time through Web-based systems. The importance of meeting all rock and fluid data-acquisition objectives cannot be overstated, given the high cost of offshore operations and the implications of obtaining false or misleading information. The main objective of real-time monitoring remains to assure that the planned data are acquired according to pre-established procedures and contingency plans. However, even in developed reservoirs, unexpected circumstances arise, requiring immediate response and modifications to the preplanned job procedures. Unexpectedly low or high mobilities, probe plugging, unanticipated fluid types, the presence of multiple phases, and excessive fluid contamination are but a few examples of such circumstances that would require real-time decision making and procedural modifications. Real-time decisions may include acquiring more pressure data points, extending sampling depths to several zones, extending or shortening sampling times, and repeating microhydraulic fracture reopening/closure cycles, as well as real-time permeability, composition, or anisotropy interpretation to determine optimum transient durations.
This paper describes several examples of formation tester surveys that have been remotely monitored in real time to ensure that all WFT evaluation objectives are met. The power of real-time monitoring and interpretation will be illustrated through these case studies.
Decision Making With Uncertainty While Developing Multiple Gas/Condensate Reservoirs: Well Count and Pipeline Optimization
Authors: Kabir C. S. , Gorell S. B. , Portillo M. E. , Cullick A. S. 
Published: June 2007

Summary
Well-developed methodology exists for handling uncertainty for a single reservoir. However, development of multiple fields presents a significant challenge when uncertainty in a large number of variables, such as gas in place and liquid yield, occur in each reservoir. Some of the challenges stem from our need to forecast the system behavior involving a coupled reservoir/wellbore/surface (CRWS) network for the entire spectrum of variables so that facilities can be designed for the range of fluid composition and throughput. Of course, assessing well count and sequencing well drills are some of the important objectives.
This paper describes probabilistic production forecasting with a compositional CRWS network model for nine reservoirs involved in delivering gas supply to a liquefied natural gas (LNG) plant in Nigeria. Our main objective was to use an economic indicator to select the optimal design of two main pipelines, each transporting 200 and 300 MMscf/D from the two production platforms, located 15 and 5 km, respectively, from the processing platform.
Rate and cumulative profiles showed that sustained deliverability of gas could be realized for approximately 11 years before the decline occurred in high-permeability reservoirs. In other words, uncertainty in gas in place did not surface during the plateau period, only during the decline period lasting another 5 years after the first 11. In contrast, the liquid rates exhibited a large uncertainty band throughout, a direct manifestation of the condensate yield issue. The uncertainty band among each of the 12 components aided facilities design. Differences in net present value (NPV) and discounted profitability index (DPI) were used as discriminators for discerning optimal pipe size from the standpoint of project economics.
Modeling Laboratory Permeability in Coal Using Sorption-Induced-Strain Data
Authors: Robertson Eric P. , Christiansen Richard L. 
Published: June 2007

Summary
Sorption-induced strain and permeability were measured as a function of pore pressure using subbituminous coal from the Powder River basin of Wyoming, USA, and high-volatile bituminous coal from the Uinta-Piceance basin of Utah, USA. We found that for these coal samples, cleat compressibility was not constant, but variable. Calculated variable cleat-compressibility constants were found to correlate well with previously published data for other coals. Sorption-induced matrix strain (shrinkage/swelling) was measured on unconstrained samples for different gases: carbon dioxide (CO2), methane (CH4), and nitrogen (N2). During permeability tests, sorption-induced matrix shrinkage was demonstrated clearly by higher-permeability values at lower pore pressures while holding overburden pressure constant; this effect was more pronounced when gases with higher adsorption isotherms such as CO2 were used. Measured permeability data were modeled using three different permeability models that take into account sorption-induced matrix strain. We found that when the measured strain data were applied, all three models matched the measured permeability results poorly. However, by applying an experimentally derived expression to the strain data that accounts for the constraining stress of overburden pressure, pore pressure, coal type, and gas type, two of the models were greatly improved.
Fundamental PVT Calculations for Associated and Gas/Condensate Natural-Gas Systems
Authors: Sutton Robert P. 
Published: June 2007

SummaryProblems with existing procedures used to estimate gas pressure/volume/temperature (PVT) properties are identified. The situation is reviewed, and methods are proposed to alleviate these problems. Natural gases are derived from two basic sources: associated gas, which is liberated from oil, and gas condensates, where hydrocarbon liquid, if present, is vaporized in the gas phase. The two gases are fundamentally different in that a high-gravity associated gas is typically rich in ethane through pentane, while gas condensates are rich in heptanes-plus. Additionally, either type of gas may contain nonhydrocarbon impurities such as hydrogen sulfide, carbon dioxide, and nitrogen. Failure to distinguish properly between the two types of gases can result in calculation errors in excess of those allowable for technical work. Sutton (1985) investigated high-gravity gas/condensate gases and developed methods for estimating pseudocritical properties that resulted in more-accurate Z factors. The method is suitable for all light natural gases and the heavier gas/condensate gases. It should not be used for high-gravity hydrocarbon gases that do not contain a significant heptanes-plus component. The original Sutton database of gas/condensate PVT properties has been expanded to 2,264 gas compositions with more than 10,000 gas-compressibility-factor measurements. A database of associated-gas compositions containing more than 3,200 compositions has been created to evaluate suitable methods for estimating PVT properties for this category of gas. Pure-component data for methane (CH4), methane-propane, methane-n-butane, methane-n-decane, and methane-propane-n-decane have been compiled to determine the suitability of the derived methods. The Wichert (1970) database of sour-gas-compressibility factors has been supplemented with additional field and pure-component data to investigate suitable adjustments to pseudocritical properties that ensure accurate estimates of compressibility factors. Mathematical representations of compressibility-factor charts commonly used by the engineering community and methods used by the geophysics community are investigated. Generally, these representations/methods are robust and have been found suitable for ranges beyond those recommended originally. Natural-gas viscosity, typically estimated through correlation, has been found to be inadequate for high-gravity gas condensates, requiring revised procedures for accurate calculations.
Fiber-Optic Distributed-Temperature-Sensing Technology Used for Reservoir Monitoring in an Indonesia Steam Flood
Authors: Nath D. K. , Sugianto Riki , Finley Doug 
Published: June 2007

Summary
The world's largest steamflood operation is conducted on the island of Sumatra in Indonesia. Fiber-optic distributed-temperaturesensing (DTS) surveys are used in the Sumatra fields to provide valuable data for reservoir management. The DTS profile data can determine the temperature and extent of a "steam chest," a phenomenon that occurs when steam injected into a steam-injection well moves away from the perforations until it encounters an impermeable barrier in the formation. The steam then extends laterally until breakthrough occurs at the producing well. Because oil is produced by gravity drainage, the steam chest (also known as a steam-saturated volume) grows downward. DTS surveys also have the capacity to determine the temperature gradient for either overburden or underburden reservoirs. This information is vital for properly setting steam-injection target rates. The information is also used to mitigate steam breakthroughs and eruptions, as well as to identify bypass oil.
Steamflood operations experience many types of problems, including inefficient injection rates, wasted heat to the casing, sanding in producers, liner failures, and pump failures. There is also an ongoing need to improve the efficiencies of vapor collection systems, well-test stations, and central gathering stations. Based on these challenging problems, periodic wellbore temperature surveys are required to improve heat management and, ultimately, profitability. Conventional temperature logs cannot be run in these wells without first pulling the pumps from the completion. Therefore, a fiber-optic DTS system attached to the production tubing was suggested.
This paper will present case histories of successful applications of fiber-optic DTS surveys that improved steamflood management in this steamflood field in Indonesia.
The benefits from fiber-optic DTS monitoring were
Significant improvement in the understanding of steam breakthrough zones along the pay-zone interval of production wells Improved understanding of the steam path in steam-injector wells Improvement of the real-time temperature profile in observation wells to identify steam-zone development and unswept or bypassed oil zones in the steamflood patterns
Recent Advances in Aphron Drilling-Fluid Technology
Authors: Growcock F. B. , Belkin A. , Fosdick M. , Irving M. , O'Connor B. , Brookey T. 
Published: June 2007

Summary
Aphron drilling fluids are being used globally to drill depleted reservoirs and other underpressured zones. The primary features of these fluids are their unique low-shear rheology and the presence of aphrons, which are specially designed pressure-resistant microbubbles of air. However, how aphron drilling fluids work is not well understood, which limits acceptance of this technology. Recently, a study was undertaken under the auspices of the US Department of Energy (DOE) to gain some understanding of aphron drilling fluids and provide guidance about running these fluids in the filed to optimize performance.
Various laboratory techniques were applied to determine the physicochemical properties of aphrons and other components in the fluid and how they affect flow through permeable and fractured media. These included wettability and surface tension, bubble stability, radial and dynamic flow visualization, and fluid displacement tests.
One key discovery was that aphrons can survive compression to at least 4,000 psig, whereas conventional bubbles do not survive pressures much higher than a few hundred psig. When drilling fluid migrates into a loss zone under the drill bit, aphrons move faster than the surrounding liquid phase and quickly form a layer of bubbles at the fluid front. The bubble barrier and radial-flow pattern of the fluid rapidly reduce the shear rate and raise the fluid viscosity, severely curtailing fluid invasion.
Another key finding is that aphrons show little affinity for each other or for the mineral surfaces of the pore or fracture. Consequently, the seal they form is soft, and their lack of adhesion enables them to be flushed out easily during production. Equally important, the interfacial tension between the base fluid and produced oils or gases is quite low, so that produced fluids do not create a formation-damaging high-viscosity emulsion; instead, they channel through the drilling fluid with relative ease.
Depleted wells, which are very expensive to drill underbalanced or with other remediation techniques, have been drilled overbalanced with the aid of aphron drilling fluids.
Generalized Functional Models for Drilling Cost Estimation
Authors: Kaiser Mark J. , Pulsipher Allan G. 
Published: June 2007

Summary
A new approach to drilling cost estimation is presented that establishes a general framework for cost estimation using a formalized systems perspective. A generalized functional approach is developed that combines regression-based techniques, as used in the Joint Association Survey (JAS), with the multidimensional attributes of drilling, as incorporated in the Mechanical Risk Index (MRI), Directional Difficulty Index (DDI), and Difficulty Index (DFI) models. A generalized methodology for framing the drilling cost estimation problem is presented and illustrated using a stylized example.