bluuebunny/crossref_metadata_2025 huggingface dataset:
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

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

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

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

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

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

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

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

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

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

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

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.
Method and Application of Cyclic Well Testing with Production Logging
Authors: Rochon J. , Jaffrezic V. , Boutaud de La Combe J. L. , Azari M. , Roy S. , Dorffer D. , Webb A. , Singer J.
Published: September 2008

One of the predicaments of traditional well testing is the requirement of shutting-in a well to conduct a pressure buildup test for the purpose of obtaining well and reservoir properties. This deterrent factor is more prominent in prolific wells due to loss of revenue and problems associated with crossflow or when bringing a well back on production. Moreover, in case of commingled reservoirs, conventional buildup provides only average values of permeability, skin, and pressure.

An innovative periodic well testing technique named WTPL (Well Testing by Production Logging) has been developed in which a cyclic wave function is imposed in the wellbore by modulating the flowrate. The analysis of the acquired rate function and the resulting pressure wave then provides formation characteristics such as permeability and skin in the vicinity of the well. This technique eliminates the disadvantage of shutting-in a well and maintains the production with a modulating periodic pattern. In addition, the WTPL can be easily applied to commingled reservoirs to estimate the individual permeability and skin for each layer. This effort has also resulted in the development of a downhole flow modulation tool capable of creating the cyclic flow patterns needed for the new testing method.
Best Practices for Formation Testing in Low Permeability Reservoirs
Authors: Weinheber Peter , Boratko Edward , Contreiras Kilamba Diogo , Van-Dunem Francisco , Spaeth Robert , Dussan V E B , Rueda Marco , Gisolf Adriaan
Published: September 2008

The data provided by wireline formation testers (WFT) is critical to the evaluation and understanding of petroleum reservoirs. Pretest pressures, gradients and mobilities are generally regarded as essential inputs to the reservoir evaluation model. However, acquiring this data in low permeability reservoirs can prove challenging. There is no stable flowing pressure during the pretest, build-up times can be long and the confidence level of the final pressure is often uncertain. These issues are painted on the ever-present backdrop of supercharging that can limit the data's utility or, in some cases, invalidate the results.

New generation formation testing tools that extend the range of pretest rates and volumes have greatly improved the quality of WFT data acquired in low permeability reservoirs. Job design and planning has always been important for the proper acquisition of formation test data. Several new options, made available through the enhanced capabilities of the new generation of tools, makes packer/probe and parameter selection even more critical. Additionally, the challenges of the low permeability environment require specific attention to real time quality control and evaluation of the test data as it is acquired.

In this paper we discuss best practices for formation testing in low permeability reservoirs with examples from the US Land area and an offshore carbonate formation in West Africa. We show the pitfalls that can arise with incorrect test design as well as the improvements brought by the latest tools when correctly configured.

While there is usually confidence in the mobility data from high permeability reservoirs the numbers generated from low permeability reservoirs is often suspect: pretest volumes are typically very low and there is no stable flowing pressure. In the examples the WFT probe results are compared and validated with subsequent mobility measurements made with inflatable dual packers.
Frequentist Meets Spatialist: A Marriage Made in Reservoir Characterization and Modeling
Authors: Ma Y. Z. , Seto A. , Gomez E.
Published: September 2008

As a branch of spatial statistics, geostatistics is commonly used to model geologic facies and petrophysical properties. The spatial characteristics of geostatistical methods in variogram, kriging and stochastic simulation have made them the tools of choice for reservoir modeling. Such techniques are especially useful to characterize the reservoir connectivity and sweep efficiency. However, geostatistical modeling methods do not always make an accurate inference of reservoir properties from well-logs to a reservoir model because of the stationarity and ergodicity assumptions and the multiscale of subsurface heterogeneities. This often causes incorrect frequency statistics of reservoir properties, which typically exhibit a non-Gaussian distribution. As a result, estimation of the hydrocarbon in-place and recoverable reserves can be grossly inaccurate and hundreds of millions of barrels of hydrocarbons can be lost or fictitiously added in a reservoir model. An accurate reservoir characterization should include not only the realistic description of the spatial continuity but also the sound inference of the reservoir properties from fine-scale well-logs to coarse-scale reservoir models. The latter can be achieved through appropriate inference of frequency statistics coupled with spatial statistics.

An application of using both spatial and frequency statistics in a real reservoir modeling example is presented. Facies probability maps were derived from geologic propensity analysis coupled with well-log data, and used for constraining the model to honor the facies spatial association of the reef complex. Careful examination of frequency statistics helped to detect the estimation biases in the initial geostatistical model. An enhanced reservoir modeling workflow with inference coupling spatial and frequency characteristics of the geologic propensity and well-log data was developed, which resulted in a more realistic model. The history match and production performance forecast using the new model was straightforward. More importantly, the new model shows more than 100 million barrels of additional oil in-place compared to the previous geostatistical models and uncertainty evaluation based on the facies scenarios and other geologic and petrophysical variables confirms the new result. The realization of more subsurface resource has implications for future field development to target unswept oils in the reservoir.
Pushing the Limit: High-Rate Artificial-Lift Evaluation for a Sour, Heavy-Oil, Thermal EOR Project in Oman
Authors: Lanier G. H. , Mahoney M.
Published: September 2008

Petroleum Development Oman LLC (PDO) currently operates the subject sour, heavy-oil (14 deg API) field which has produced since 1976 from a naturally-fractured, carbonate reservoir located in the northern region of the Sultanate of Oman. Further field development options have recently been evaluated and the preferred concept will be based upon thermal-assisted gas oil gravity drainage (TAGOGD). To achieve this enhanced oil recovery mechanism, steam will be injected into the reservoir and eventually increase produced fluid temperatures to more than 200 deg C during the projected life of the project.

A key objective for the project will involve significantly increasing the field's ultimate recovery utilizing high-rate oil producers capable of initially delivering over 1000 m3/d gross rate per well. To achieve these well offtake rates and field ultimate recovery objectives, highly-deviated and near-horizontal well trajectories will be employed for the planned oil producers. This paper will provide a brief background of the TAGOGD recovery mechanism, anticipated reservoir conditions and particular challenges including a summary of the evaluation of various artificial-lift technologies and preferred method to help enable this thermal EOR project achieve the desired objectives.
Innovative Frac Stimulation of Low-Perm Oil Zone in High-Deviation Well Offshore Congo
Authors: Lemesnager Fabien , M'Bouyou Patrick , Gavalda Jean , McDaniel B. W. , Quero Philippe , Ranjeva Jean-Michael , Cortier Alexandre , Hurey Michael
Published: September 2008

Total operates an offshore oil field approximately 60 Km West of Pointe-Noire, Republic of Congo. To date, the Albian reservoir has contributed most of the oil produced. However, a significant part of the oil in place is in the Cenomanian, a low permeability sandstone formation with poor quality. As of early 2007, only two of the initial 50 wells in the field had been completed in the Cenomanian. It was desired to evaluate the potential of hydraulic fracturing stimulation treatments to more fully comprehend the production capability of this reservoir. In early 2007, a third well was drilled and completed in this structure, penetrating the Cenomanian at a 60 degree inclination for this purpose.

Proppant fracturing from a wellbore with a 60 degree inclination in a hard-rock formation has always been difficult. Also adding another level of uncertainty was the fact that the Cenomanian has never been fracture stimulated.

This paper will detail the planning process from both the operator and the service provider perspectives with specific well control issues related to an over-pressured reservoir. Review of the well conditions and operational constraints indicated the best approach would be a multi-stage pinpoint stimulation method incorporating hydrajet perforating and sand plug isolations using a stimulation vessel especially designed for such work. Additionally, a comprehensive review of the actual three-stage stimulation treatments will detail the perforating, fracturing, and sand plug isolation after each stage. With BH memory gauges just below the jetting tool assembly, post-frac reviews of downhole pressure data is compared with the live annulus data used for real time decisions during the stimulation stages. Post-frac well cleanup and early production data will be included.
Characterization and Modeling Study of the Carbonate-Fractured Reservoir in the Cantarell Field, Mexico
Authors: Shen Feng , Villavicencio Antonio Pino , Garcia Jesus Hernandez , Bustos Arturo Vazquez , Avendano JoseLuis Rodriguez
Published: September 2008

An integrated fracture characterization and modeling study has been performed on a large reservoir, Cantarell field, Mexico. This paper presents the methodology used for analyzing and integrating multi disciplinary datasets in order to identify main types of fractures, to predict their distributions in the reservoirs and to determine the hydraulic properties of different fracture sets. There are three sets of conductive fractures interpreted from FMI data with the consideration of reservoir geomechanics, which strike in 0°~50°, 80°~120° and 140°~180°. For each set of fractures, two scale fractures are focused: large scale fractures (sub-seismic faults and fracture corridors) and small scale fractures. 3D seismic volumetric attributes, describing reservoir coherence, dip, azimuth and lineaments, are used for the seismic facies analysis. An integrated interpretation of the facies and attribute characters, along with the geological studies, leads to quantifying and ranking fracture contents. The large scale fractures are modeled based on the structural lineaments from the ranked facies. For small size fractures, the 3D statistic fracture model is generated by a sequential Gaussian simulation technique with FMI logs and constrained with ranked facies and maximum curvatures. A 3D stochastic fracture model is then generated incorporating the two scale fractures. Correlation with flow profiles, lost circulation, water breakthrough and product index is studied in order to qualitatively determine the fluid conductivity of modeled large scale fractures. A strategy is proposed to combine two scale fractures to produce the 3D fracture property model of the reservoir. The well test analysis is used to calibrate the fracture permeability quantitatively and help to understand the main flow mechanisms occurring in the reservoir. The model of permeability conduits, calculated from fracture networks and calibrated with dynamic data, can be used for well planning and simulation. In this paper, case studies are used to illustrate applications of these technologies and their efficiency.
Ocean Sustainability and Stakeholders: The Future of Oil and Gas Industry Operations in the Marine Environment
Authors: Holthus P. F.
Published: September 2008

Oceans and coasts provide the majority of the world's ecosystem benefits. The marine environment is increasingly critical to the future of oil and gas resources as more exploration and production occurs there, and the maritime transport of industry products continues to grow. While the industry has been proactive in developing discreet projects to respond to perceived challenges, ocean management regimes, such as marine protected areas, are being determined by governments, intergovernmental bodies and NGOs in a variety of fora.

There is a need to develop integrated ocean strategies and partnerships to ensure that energy requirements are met without damage to important ocean ecosystems. In addition, the industry needs to engage on ocean sustainability issues with the other sectors of the ocean business community (shipping, fisheries, cruise ships, etc) – and with other stakeholders (government, intergovernmental, NGO). A multi-sectoral and multi-stakeholder approach can result in cost-savings (e.g. collaborative research to find science-based solutions to shared issues) and reduce the risk of costly, unplanned and unnecessary restrictions to operations in the marine environment.

This paper will provide a global overview of the issues, the stakeholders, actions to date, and legal context critical to industry operations potentially constrained by ocean environment concerns, and identify potential strategies, options and priorities for action.
Critical Review of Existing Solutions to Predict and Model Liquid Loading in Gas Wells
Authors: Solomon F. A. , Falcone G. , Teodoriu C.
Published: September 2008

Liquid loading in gas wells is a multiphase flow phenomenon where the liquid content of the well creates back pressure (usually dominated by gravitational pressure changes) which restricts, and in some cases even stops, the flow of gas from the reservoir. The industry recognizes the importance of liquid loading and tries to alleviate the problem using various measures, yet the fundamental understanding of the associated multiphase phenomena remains weak. This paper discusses the complexity of the multiphase flow phenomena associated with liquid loading in gas wells. An extensive review of the current modeling solutions available to predict the arrival of liquid loading, diagnose its impact on production and screen remedial options is presented. The paper also critically reviews recent attempts to model the dynamic interactions between reservoir and wellbore. The review highlights the limitations of the current models, stressing the need for a fully transient multiphase flow approach.
Development of a New Plunger-Lift Model Using Smart Plunger() Data
Authors: Chava G. K. , Falcone G. , Teodoriu C.
Published: September 2008

The problem of liquid loading, which is common to all mature gas producing wells, needs to be identified and solved in order to achieve efficient gas production. Field operators not only need to select the best possible technical solution for liquid loading, but also one that is cost effective.

A popular remedial solution for liquid loading in onshore gas wells is plunger lift. However, this technology is currently designed using simplistic models with restrictive assumptions, coupled with field experience.

This paper provides an overview of the various plunger lift models available in the public domain and highlights their fundamental limitations. A new approach to plunger lift modeling is then proposed, which assumes the availability of pressure and temperature data provided by smart plungers. These devices are equipped with internal gauges to record pressure and temperature with time, which can be downloaded whenever the plunger is at surface. In the proposed model, these data are coupled with the fundamental conservation equations of mass, momentum and energy that govern the dynamics of plunger lift. The main difficulties of dealing with transient flows that are typical of plunger lift operations are identified. These include the dynamic interactions between reservoir, annulus and tubing, which are particularly relevant in tight gas reservoirs. The overall objective is to develop a model capable of predicting plunger lift operations in a more realistic fashion and so optimize lift cycles.
Investigation of Swirl Flows Applied to the Oil and Gas Industry
Authors: Surendra Meher , Falcone Gioia , Teodoriu Catalin
Published: September 2008

The work presented in this paper is part of a larger Research Project which is aimed at finding solutions to problems associated with liquid loading, erosion at pipe bends due to sand particles and phase separation. The work uses computational fluid dynamics (CFD) to design solutions that can reduce or eliminate the aforementioned problems. Here, the results from CFD simulations of two-phase air and water flows are critically analyzed via comparison with the results from experiments carried out by Falcone et al. (2003) using the ANUMET* concept. The entire experimental setup is modeled within the CFD simulation and flow rates for water and air are taken from the data used for the experiments. Important variables such as pressure drop and fluid film thickness, which were monitored closely during the experiments, are obtained from the CFD simulations and compared with the experimental results. The results presented in this paper provide insights into the physics of two-phase swirl flows, identifying areas of research that still need to be addressed.
Effect of Salinity and pH on Pickering Emulsion Stability
Authors: Wang X. , Alvarado V.
Published: September 2008

The stability and morphology of crude-oil emulsions with and without suspended kaolinite or silica were investigated as functions of salinity. First, synthetic reservoir brine with 1, 10 and 100 times dilution was emulsified with crude oils of commercial interest, at several water-oil ratios, on which salinity effect on emulsion stability was studied. Also, the emulsion was prepared by mixing this oil with 100 times dilution dispersed with particles to investigate pH effect on emulsion stability. The clay zeta potential at different pH was measured to estimate the effect of particle charge on emulsion stability. Clay particle-size distribution, which impacts the formation and stability of emulsions, was obtained using light diffraction. The stability of emulsion was determined by simple bottle tests and by using an optical microscope equipped with a digital camera. Our results show that both kaolinite and silica promote emulsion stability. Most emulsions turned out water-in-oil. Also, kaolinite of the order of 1μm in size more easily adsorb at the oil-water interface, while silica with larger diameter, such as 5μm, can form more stable emulsions than with 1μm and 3μm. Zeta potential measurements and bottle tests clearly show that clay particles with zero point of charge (ZPC) at low pH become less effective at stabilizing emulsions in contrast with reservoir conditions, while silica shows the opposite behavior, stabilizing better emulsion at ZPC. Salinity, especially calcium concentration, affects the morphology and stability of emulsions. We can conclude that low-salinity waterflooding provides adequate conditions for formation of relatively stable emulsions, provided kaolinite detachment occurs. This is also apparent in reports of produced water re-injection.
Numerical Modeling of Pressure and Temperature Profiles Including Phase Transitions in Carbon Dioxide Wells
Authors: Paterson Lincoln , Lu Meng , Connell Luke D. , Ennis-King Jonathan
Published: September 2008

Geological storage of carbon dioxide will usually be at conditions above the critical temperature and pressure, so the carbon dioxide will exist as a single dense phase. However, conditions in the upper part of a carbon dioxide well with surface temperatures below the critical point of 31 C can lead to boiling and condensation in the well. The consequences of this are most apparent when flow rate changes, for example when a well is shut-in or if there is a well blowout.

We have calculated density profiles for wells experiencing different thermal conditions to determine how bottom-hole pressures are related to wellhead pressures. There are two limiting cases, one when the fluid is in thermal equilibrium with the rock at the same horizon, the other when there is no heat exchange with the casing or the rock. We find that in deeper wells static columns can exist in a stable state with liquid to the surface, but for shallower wells or wells in depleted reservoirs that a static column can be initially unstable with two-phase conditions near the surface.

In producing wells, as the flow rate increases from static conditions, the pressure and temperature at the wellhead increases until high production rates are reached when the wellhead temperature then decreases, which can be to very low values. For injection wells, bottom-hole conditions are confined between the wellhead and the reservoir temperature.

In general, phase change does not prevent carbon dioxide injection. Nevertheless care is needed in shallower or depleted reservoirs for the interpretation of reservoir pressure, the use of pressure for monitoring, and in all reservoirs for the management of blowouts.
Effect of Diffusion on Dispersion
Authors: Jha Raman K. , Bryant Steven L. , Lake Larry W.
Published: September 2008

We study dispersion in porous media by tracking movement of a swarm of solute particles through a physically representative network model. We developed deterministic rules to trace paths of solute particles through the network. These rules yield flow streamlines through the network comparable to those obtained from a full solution of Stokes’ equation. In the absence of diffusion the paths of all solute particles are completely determined and reversible. We track the movement of solute particles on these paths to investigate dispersion caused by purely convective spreading at the pore scale. Then we superimpose diffusion and study its influence on dispersion. In this way we obtain for the first time an unequivocal assessment of the roles of convective spreading and diffusion in hydrodynamic dispersion through porous media. Alternative particle tracking algorithms that use a probabilistic choice of an out-flowing throat at a pore fail to quantify convective spreading accurately.

For Fickian behavior of dispersion it is essential that all solute particles encounter a wide range of independent (and identically distributed) velocities. If plug flow occurs in the pore throats a solute particle can encounter a wide range of independent velocities because of velocity differences in pore throats and randomness of pore structure. Plug flow leads to a purely convective spreading that is asymptotically Fickian. Diffusion superimposed on plug flow acts independently of convective spreading causing dispersion to be simply the sum of convective spreading and diffusion. In plug flow hydrodynamic dispersion varies linearly with the pore-scale Peclet number.

For a more realistic parabolic velocity profile in pore throats particles near the solid surface of the medium do not have independent velocities. Now purely convective spreading is non-Fickian. When diffusion is non-zero, solute particles can move away from the low velocity region near the solid surface into the main flow stream and subsequently dispersion again becomes asymptotically Fickian. Now dispersion is the result of an interaction between convection and diffusion and it results in a weak non-linear dependence of dispersion on Peclet number. The dispersion coefficients predicted by particle tracking through the network are in excellent agreement with the literature experimental data.

We conclude that the essential phenomena giving rise to hydrodynamic dispersion observed in porous media are (i) stream splitting of the solute front at every pore, thus causing independence of particle velocities purely by convection, (ii) a velocity gradient within throats and (iii) diffusion. Taylor's dispersion in a capillary tube accounts for only the second and third of these phenomena, yielding a quadratic dependence of dispersion on Peclet number. Plug flow in the bonds of a physically representative network accounts for the only the first and third phenomena, resulting in a linear dependence of dispersion upon Peclet number.
Rewarding and Reducing Risk: Harnessing the Potential of Entrepreneurs in the Oil & Gas Industry
Authors: Preston Robert , Leggett Nigel
Published: September 2008

This Paper examines the financial and industry mindset barriers which exist at either end of the research and development (R&D) process for entrepreneurial businesses commercialising new technology for the Oil & Gas services (O&G) sector.

It examines the core business skills entrepreneurs require to secure adoption of their technology in a competitive market and whether respondents felt they possessed these skills – particularly the ‘human’ factor; industry contacts and relationships, communication skills and product marketing.

Using a research model developed by Professor Shailendra Vyakarnam, Director Cambridge Centre for Entrepreneurial Learning, the report examines the industry and compares the funding climate to comparative sectors where entrepreneurial innovation is crucial in order to build a valuable business which will ultimately attract potential acquirers of the company or its technology.
Fluid-Phase Behaviour for a Miscible-Gas-Injection EOR Project in a Giant Offshore Oil Field With Large Compositional Variations
Authors: Lindeloff N. , Mogensen K. , van Lingen P. , Do S. H. , Frank S. , Noman R.
Published: September 2008

Gas injection as an EOR method is being considered for the giant Al Shaheen field, located offshore Qatar. The field is characterized by large lateral variations in fluid properties across the field. The oil gravity ranges from 16 to 38 °API and significant variations in initial GOR and saturation pressure are observed. The field is developed with horizontal wells with up to 35,000 ft long reservoir sections. The oil gravity may vary considerably along a horizontal well, which needs to be considered when evaluating further field development options involving miscible as well as immiscible gas injection.

An extensive experimental program aimed at establishing a model for the miscibility behavior for this complex fluid system is described. The work resulted in the development of an equation of state (EOS) model capturing the miscibility behavior across the range of API gravities, as well as a set of black oil correlations consistent with the EOS.

A method for initializing compositional reservoir simulations with the developed EOS based on API, GOR and saturation pressure maps of the field was developed. This methodology allowed a finely discretized compositional variation to be represented in the compositional simulation models giving an accurate and detailed fluid phase behavior description.