bluuebunny/crossref_metadata_2025_split huggingface dataset:
Actual 3D Shape of Wellbore Trajectory: An Objective Description for Complex Steered Wells
Authors: Liu Xiushan , Samuel Robello 
Published: September 2008

Abstract
All conventional methods for calculating the trajectory of a wellbore involve assumptions. Most calculations assume that segments of the trajectory can be approximated as straight lines, polygonal lines, cylindrical helixes, circular arcs, or combination of these approximations. Conventional methods calculate the course coordinates of a well survey interval according to the predetermined shape for the trajectory. But, what does the real shape of a trajectory in each surveyed interval really look like? Why? What parameters play decisive roles in determining the true shape of a surveyed interval? Is it reasonable to assume that every survey interval has the same kind of approximate shape? Until now, the drilling industry has not found satisfactory solutions to these questions.
This paper presents the results of research about the true shape of a wellbore trajectory relative to its survey stations. It also provides a universal equation for a wellbore trajectory in a surveyed interval and presents an objective approach for describing and calculating a wellbore trajectory in space. The new method does not assume that the shape of wellbore trajectory is a set of typical approximations. The study shows that the wellbore curvature and torsion at survey stations determine the shape of the wellbore trajectory at subsequent intervals, and that 3D coordinates of wellbore trajectory in a local coordinate system are linear, quadratic, and cubic functions vs. curve length, respectively. The new method yields a continuous wellbore trajectory. Extensive simulations have been carried out and are reviewed in this paper. The paper compares the results predicted by mathematical simulation using the new method with actual, observed trajectories and describes the results from other methods to show the accuracy of the new, improved method. The new method shows excellent precision in calculation and reliability.
This study has also proved that the minimum curvature method and the natural curve method, the most commonly used methods, are related to the new method.
Evaluating the Technologies To Ensure Produced Water From Trinidad Land Operations Conform To Specification Before Discharge into the Environment
Authors: Sookdeo Nigel , Jaggernauth Deonarine J. 
Published: September 2008

Abstract
The National Oil Company of Trinidad, which has operations throughout the south of the island, currently produces 35,000 barrels of water per day (bwpd). While every effort is being made to ensure conformity before discharge, there are twenty-eight (28) parameters which have to be addressed immediately. The new legislation in the country requires all companies conform to the specification laid down by the Environmental Management Authority (EMA). Conventional primary and secondary technologies currently in use, do not allow us the capability to address these parameters. An evaluation was carried out on two types of technology namely the membrane filtration/reverse osmosis, and the electro coagulation/variable vacuum distillation. The introduction of either technology can assist companies with oil field operations on land in Trinidad to conform to the required specification. If the use of the technology is costly, then arrangement can be derived from a service company to provide the facility and seek alternate arrangement as to recover the cost of the operation.
Gas Condensate Relative Permeabilities in Propped Fracture Porous Media: Coupling Versus Inertia
Authors: Jamiolahmady M. , Sohrabi M. , Ireland Shaun 
Published: September 2008

Abstract
Hydraulic fracturing is one of the most common well stimulation techniques for gas-condensate reservoirs. In recent years considerable effort has been directed towards understanding of flow around hydraulically fractured wells especially for tight gas reservoirs. However, there has been no report of a study of flow behaviour within propped fractured porous media for these low interfacial tension (IFT) systems.
It is now a well established finding both experimentally and theoretically that the flow of gas-condensate fluid systems in porous media is affected by both coupling (the increase of relative permeability (kr) as velocity increases and/or IFT decreases) and inertial (i.e., the reduction of kr as velocity increases) effects. However, the interaction of capillary, viscous and inertial forces within highly conductive propped fractures is yet unknown.
In this work, we report a series of steady state gas-condensate relative permeability values for a proppant filled and a sand packed fracture with permeability of 146 D and 15 D, respectively. These sets of kr data, which have been measured using our unique experimental facilities, covers IFT and velocity values ranging between 0.85 and 0.15 mNm−1 and 250 to 3000 md−1, respectively.
The results indicate that inertia is quite dominant at all the tested conditions albeit to a greater extent at lower IFT and higher gas fractional flow rates. In the case of the fracture with the higher permeability, some kr values measured at the higher IFT are also reported, which are higher than the corresponding values at a lower IFT. We also compare the results with the corresponding predicted kr values by the generalized kr correlation, which we reported recently and expresses the combined effect of coupling and inertia with universal parameters. The unique contribution of inertial forces, as observed in the experiments and predicted by the correlation, is mainly attributed to the impact of the fracture properties and the fluid flowing in the fractures.
Mechanisms of Meniscus Motion in Fractionally Wetted Porous Media
Authors: Motealleh Siyavash , Ashouripashaki Mandana , DiCarlo David , Bryant Steven 
Published: September 2008

Abstract
Oil reservoirs and soil are often heterogeneously wetted (mixed wettability or fractional wettability). In mixed-wet reservoirs the mechanism of wettability alteration means that a single grain can have patches that are water-wet and patches that are oil-wet. In fractionally-wet porous media each grain is either oil-wet or water-wet. Here we develop a mechanistic model of capillarity-controlled fluid movement in fractionally-wet media. The model calculates the position of stable interfaces between grains of arbitrary wettability. Pore filling occurs when the interface becomes unstable in a pore throat (Haines condition), or when two or more interfaces come into contact and merge to form a single interface (Melrose condition). The model is robust and general in the sense that both filling mechanisms are considered simultaneously during arbitrary sequences of changes in capillary pressure. The model is demonstrated on 2-D porous media consisting of randomly distributed oil-wet and water-wet disks, and capillary pressure – saturation curves are obtained. The model results compare favorably with imbibition experiments on fractionally-wet media. Most notably, a distinctive shift in the drainage/imbibition curves occurs as the fraction of oil-wet grains increases beyond a threshold value.
Accurate Modeling of Relaxation Time and Liquid Holdup for Multiphase Flow in Production Wells
Authors: Michel Guillermo , Civan Faruk 
Published: September 2008

Abstract
A homogenous model applicable for reservoir fluids flowing along a pipe with constant cross-sectional area is presented. This model is simplified for flowing fluids across a circular pipe at steady state. The differential conservation laws of mass, momentum, and energy are applied. By estimating the multiphase fluid properties, the differential laws of conservation are solved to compute the change in the pressure, temperature, and flowing velocity. The velocity is computed by knowing the fluid density. Because the flow might not be in equilibrium, the density of the multiphase fluid system is not calculated from any equation of state. Two approaches are presented to determine the density at non-equilibrium conditions. One is the differential conservation law of gas mass that can be solved by estimating the relaxation in time of gas separation, and the other is predicting the liquid holdup by estimating the slip ratio which is the ratio of the phase velocities. The later was used for the application. The presented homogeneous model combined with the proposed and novel liquid holdup model is applied to the study cases. The results of the application are employed to predict and characterize the nature of the relaxation time for hydrocarbon fluids.
Improved Drilling and Completions Decisions Using Advanced Data Quality Profiling Techniques
Authors: Gregory Paul 
Published: September 2008

Abstract
This paper explores how three different E&P companies used "data quality profiling" techniques to enhance strategic drilling & completions decisions and data management. Although each company had a different reason for data quality profiling, the results all indicated a higher level of trust and confidence in the data over time.
Especially in the current climate of "blow and go" activity, many drilling decisions are bets based on the best available data at the time. Multi-million dollar mistakes can be made if data used is incomplete, inaccurate, or inconsistent. Our case study E&P companies realized that they are more than engineering operations – they are in fact asset management companies, where data is their most valuable asset. Since their drilling performance is predicated on accurate data, it was vital to ensure that reservoir and well data gathered from different sources and disciplines is of the very highest quality and integrity.
A fundamental first step taken by the three E&P's in the case study was to perform "data quality profiling" to identify any and all possible data issues. Learn how data quality profiling is an emerging technique that automates the ability to tag "trustworthy vs. untrustworthy data" when it pertains to drilling decisions.
Field Application of an Interpretation Method of Downhole Temperature and Pressure Data for Detecting Water Entry in Inclined Gas Wells
Authors: Achnivu Ochi I. , Zhu D. , Furui Kenji 
Published: September 2008

Abstract
Accurate and reliable downhole data acquisition has been made possible by advanced permanent monitoring systems such as downhole pressure and temperature gauges and fiber optic sensors. These downhole measurement instruments are increasingly incorporated as part of the intelligent completion in complex (highly slanted, horizontal, and multilateral) wells where they provide bottomhole temperature, pressure and sometimes volumetric flow rate along the wellbore. To fully realize the value of these intelligent completions, there is a need for a systematic data analysis process to improve our understanding of reservoir and production conditions using the acquired data and to make decisions for well performance optimization.
We have successfully developed a model to predict well flowing pressure and temperature (i.e. the forward model), and applied inversion method to detect water and gas entry into wellbore using the synthetic data generated by the forward model (i.e. the inversion model) in the previous study. It is concluded that temperature profiles could provide sufficient information to identify fluid entries, especially in gas wells. However, both the mathematical complexity and advanced well structure lead to challenges in model validation and application. In this study, we applied the wellbore-reservoir flow coupled thermal simulation model to high-rate gas wells with field data. The main objectives are to evaluate applicability of the model to field problems, to study the sensitivity of parameters such as permeability and reservoir pressure on accuracy of interpretation, and to generate practical guidelines on how to initialize the inversion process. The model is applied to highly-slanted gas wells with water produced from a bottom aquifer. The interpretation result was compared against production logging data. The sensitivity of interpretation error to input reservoir properties are examined and the results showed that temperature and pressure anomalies caused by water production and flow rate changes can be detected theoretically and also practically. Judgments should be used based on the understanding of temperature and pressure behavior when initializing the forward model and this can increase efficiency of model application. The study results and guidelines developed in this study will help us to design permanent monitoring systems and set realistic expectation for predictive capability of intelligent well systems.
Using Swellable Packers to Provide Annular Isolation for Multistage Fracture Treatments
Authors: Davis Tim , McCrady Doug 
Published: September 2008

Abstract
For years the industry has used horizontal drilling as a method to convert marginal reservoirs into profitable reservoirs. Until recently, horizontal drilling has been reserved for conventional reservoirs and some unconventional formations such as vertically fractured shales. The challenge of extending horizontal drilling into the arena of formations with nano-darcy permeability has been difficult. These low permeability formations must be stimulated with multi-stage fracture treatments. Early attempts resulted in inefficient treatments over the complete length of the lateral. One of the most challenging aspects of multistage, horizontal fracture design treatment is ensuring proper annular isolation. This paper examines the use of swell packers as a simple, cost effective method of achieving necessary isolation.
One of the most important aspects of horizontal fracture treatment is the ability to effectively execute multistage treatments without the use of a drilling rig. For this to occur each stage must be isolated. Liners cemented in the horizontal portion of the wellbore can be effective, but the cement may cause an unacceptable level of formation damage. Uncemented liner completions have been employed, relying on diversion built into the treatment designs. Another method is to employ mechanically or hydraulically activated external casing packers to provide annular isolation. In this method, frac sleeves and balls of varying sizes are used to open and close portions of the wellbore for stimulation.
Swellable packers have recently been used successfully to provide a positive annular barrier during a multistage fracture treatment in conjunction with sliding sleeves and plug and perf operations. Using swellable packer technology has mechanically simplified the multistage fracture job. Using multiple packers ensures the entire lateral is treated. Understanding the wellbore fluids that come in contact with the swellable elastomer as well as the maximum differential pressure and temperatures encountered is critical in designing the swellable packer.
This paper discusses current and previously employed approaches to multistage fracture treatments and the proper design of swellable packers. Finally, a case history is reviewed to present a best practice approach in using swellable packers to simplify and reduce costs on horizontal multistage fracture treatments.
Fluid Characterization: Impact on Deepwater Field Development
Authors: Tagore Anupam , Utgard Mark , Ramachandran Kartik , Paragon AMEC , Alwazzan Amir 
Published: September 2008

Abstract
As we move deeper into offshore reservoirs to increase oil and gas production, the systems get more costly and more complex to build. The challenges rise dramatically to accurately determine long lead items required for the project, such as pipe and equipment size, and identify risks and operating issues with transporting the product.
For typical project execution, Fluid Characterization (FC) is the first and the most important step taken to represent properly the interaction between fluid flow and phase behavior. FC is a direct input in the process of modeling the system with process simulators/modeling tools. Different fluids pose different risks like hydrate formation, wax issues, and asphaltenes. Incorrect FC can lead to erroneous equipment/pipe sizing and wrongly identifying risks of the fluid. This can lead to incorrect designs, increased costs, delays in schedule or operating challenges once the system is up and going.
Fluid characterization involves using a fluid composition and adjusting the composition to match laboratory test. The end result of the fluid composition is key properties of the fluid at different pressure and temperatures and using these properties in process simulators.
Fluid characterization should be prioritized early in a project to ensure that adequate samples are obtained and to ensure the correct laboratory tests are completed for adequate fluid characterization. Early involvement allows the most accurate results to be obtained with fluid characterization and assists to predict fluid behavior with higher level of accuracy.
Flow Rate Estimation From Wellhead Pressure and Temperature Data
Authors: Izgec B. , Hasan A. R. , Lin D. , Kabir C. S. 
Published: September 2008

Abstract
Flow rate metering has less-than-satisfactory track record in the industry; modern sensors offer solution to this vexing problem. This paper offers two methods for estimating flow rates, predominantly from temperature data to complement rate measurements. One approach consists of modeling the entire wellbore and requires both wellhead pressure and temperature, whereas the other uses transient temperature formulation at a single point in the wellbore to compute the total production rate.
In the entire-wellbore approach, we use a wellbore model handling steady flow of fluids but unsteady-state heat transfer to estimate production rate, given wellhead pressure and temperature. The model rigorously accounts various thermal properties of the fluid and the formation, including Joule-Thompson heating and/or cooling. In the single-point approach, a single point temperature measurement made anywhere in the wellbore, including at the wellhead, is needed to estimate the mass rate at a given timestep. The method entails full transient treatment of the coupled fluid and heat flow problem at hand.
Examples from both gas and oil wells are shown to illustrate the application of the proposed methodology. Good correspondence between the measured and calculated results demonstrates the robustness of the proposed methods. These methods provide important rate information in various settings. For instance, in mature assets they can fill in the information void between tests or replace suspect rate data. Even well-instrumented wells can benefit because the methods can act as a verification tool, particularly in assets where integrated asset models are used to fine-tune rate allocation. In addition, the single-point approach can provide the much needed rate information during pressure-transient tests.
Analysis of Permanent Downhole Gauge Data by Cointerpretation of Simultaneous Pressure and Flow Rate Signals
Authors: Ahn Sanghui , Horne Roland N. 
Published: September 2008

Abstract
Modern permanent downhole gauges have the capability to measure both pressure and flow rate, which provides data with the potential for a wider range of reservoir analysis applications than just pressure data alone. It is important to pair the data analysis of pressure and flow rate streams together. Reservoir physics imposes a relationship between the two data sets. Investigation into the interrelation of data pairs provides a better way of characterizing the true reservoir response.
Deconvolution is an important tool for understanding the interrelationship between variable pressure and flow rate. Using convex optimization approaches to achieve deconvolution in the time domain was found to be successful in extracting the constant rate pressure response.
We evaluated the noise model of pressure and flow rate data for each pair of measurement points. We were able to estimate pairs of noise-reduced pressure and flow rate data according to the interdependence of the original data streams, thus honoring the reservoir physics. Analysis of the interrelation allowed us also to update the estimate of the constant rate reservoir response.
Investigating pressure and flow rate pairs simultaneously may improve the match and accuracy of the reservoir model. The ability to incorporate and retain interrelations suggested by true pressure and flow rate pairs is useful to the interpretation of reservoir behavior. Cointerpreting the two data streams simultaneously provides better information about the reservoir. Following noise reduction by cointerpretation, the data can then be used in more complex reservoir engineering functions, such as closed loop optimization.
Monitoring Inflow Distribution in Multi-zone, Velocity String Gas Wells Using Slickline Deployed Fiber Optic Distributed Temperature Measurements
Authors: Huebsch H. , Moss M. , Trilsbeck T. , Brown G. , Rogers S. , Bouchard T. 
Published: September 2008

Abstract
Fiber-optic systems are able to generate a temperature log along an optical fiber using a laser source and analysis of the backscattered light. This paper details a novel application of this technology using an optic fiber embedded in a 1/8th inch slickline cable to calculate the inflow distribution of multi-zone gas wells with velocity strings.
EnCana's multi-zone gas wells in the Deep Basin of Western Canada are often completed with production tubing landed near the lowest perforated interval to act as a velocity string and lift produced water to surface. This completion technique makes spinner production logs impossible to run without initially performing a wellsite operation to lift the tubing shoe above the reservoir, requiring either a workover rig or a snubbing unit. Running a slickline containing an optical fiber to the bottom of the tubing and producing the well up the annulus for a short period allows the temperature profile of the well to be measured and therefore, the inflow distribution of the well can be calculated.
Determining the inflow distribution of multi-zone gas wells now becomes a simple slickline operation with no tubing shift required. Additional benefits are the detection of crossflow on shut-in and the measurement of flowing bottomhole pressure when a gauge is run at the end of the slickline. The process is cost effective, less risky than conventional production logging, and the slickline can be safely employed where there is significant surface pressure.
The paper uses case studies validated by spinner log comparisons to demonstrate that slickline fiber optic distributed temperature sensor measurements are a viable method for performing reservoir surveillance in multi-zone gas wells with velocity strings in Western Canada. Utilizing fiber optic measurements in these wells reduces operating costs and should ultimately lead to increased efficiency of reservoir stimulation practices.