bluuebunny/crossref_metadata_2025_split huggingface dataset:
Evolution of Coil Tubing Instrumentation in SAGD Applications
Authors: Panci Miodrag 
Published: July 2010

History of Multiple Pressure Coil Tubing Instrumentation
The evolution of coil-tubing instrumentation has been primarily driven bythe ongoing development of SAGD projects. In 1995, one of the earlierproponents of the technology, Alberta Energy Company, went looking for acompany that could provide a means to instrument horizontal well pairs used inthe SAGD process. Concurrently, PROMORE Engineering Inc. had embarked on aninitiative to develop high temperature pressure sensors. The two companies setout to design and manufacture coil-tubing instrumentation that would remain drywith special ports accessing the wellbore. Initial prototypes were designed forinjection and production well(s) and incorporated multiple pressure andtemperature sensors, bubble tubes and conventional thermocouples (Figure 1).Based on continued co-operation, the two companies patented the CT-MORE(Coil-Tubing Conveyed) monitoring system in 1998, which provides theinstrumentation cornerstone of most SAGD projects today.
Commercial Development
Based on the commercialization of SAGD and the ensuing need to reduce costsfrom pilot project phases, PROMORE set out to streamline the manufacturing andinstallation process. With an initial investment exceeding $1.0 million, thecompany was able to reduce the dependence on coil-tubing services inconjunction with reducing the average size of CT-MORE Systems (Figure 2).Several design changes allowed the CT-MORE diameter to be reduced from 1-in. to1 1/4-in. Other designs were developed to improve overall wellbore hydraulicsand 1-in. and 3/4-in. CTMORE's became available. These changes and investmentreduced manufacturing costs resulting in savings to the operating companies.Figure 2 shows the decrease in manufacturing costs which resulted in largesavings to the operating companies. As noted on the plot PROMORE's investmentin SAGD resulted in a service entity with complete control over manufacturing.Note: third part coil tubing services are no longer required formanufacturing.
In addition to the manufacturing process, it became evident that newdeployment techniques and procedures would have to be developed, especially inconsideration of the use of smaller diameter CT-MORE strings. Two uniquesystems allowed the CTMORE systems to be deployed economically.
Analytical Modelling of Gas Production From Hydrates in Porous Media
Authors: Hong H. , Pooladi-Darvish M. , Bishnoi P.R. 
Published: July 2010

Abstract
Gas hydrates are being considered as an alternative energy resource of thefuture since they exist in enormous quantities in permafrost and offshoreenvironments. However, gas production potential from hydrate reservoirs throughdifferent production schemes has not been fully investigated yet. This workintroduces a simple analytical model for simulating gas production from hydratedecomposition in porous media by a depressurization method.
We consider the heat transfer to the decomposing zone, intrinsic kinetics ofhydrate decomposition, and gas-water two-phase flow as the three primarymechanisms involved in hydrate decomposition in porous media. In this study, the relative importance of these mechanisms is compared over a realistic rangeof the physical properties. It is shown that for the cases studied, the effectof two-phase flow is significantly smaller than the heat transfer and theintrinsic kinetics of hydrate decomposition. Considering the rate-controllingmechanisms, an analytical model is developed to predict the performance ofdecomposition of gas hydrates in porous media. The model is used to performsensitivity studies to investigate the feasibility of commercial gas productionfrom hydrate reservoirs. The results suggest that significant quantities of gascan be produced from gas hydrate reservoirs where the hydrate overlies the gaszone. Such reservoirs have been found in the permafrost regions of Siberia, Alaska, and Canada.

Introduction
The enormous natural gas reserves associated with the in situ gas hydratesin permafrost regions and offshore environments of the earth is expected to bean energy resource of the future. The gas could be produced from the hydratedissociation by depressurization, thermal stimulation, solvent injection, or acombination of these methods. The potential for gas production from hydratereservoirs through different production techniques is still uncertain and underinvestigation. One method of investigation is with the help of mathematicalmodels. For a mathematical model to be representative, it should include theimportant mechanisms. In a depressurization scheme considered in this study, three important mechanisms are involved: intrinsic decomposition of the hydratethat results in reduced temperature; heat flow towards the cooled zone thatprovides the necessary energy for further decomposition; and, flow of thedecomposed gas and water through the porous rock.
Field Applications of Waterflood Optimization via Optimal Rate Control With Smart Wells
Authors: Alhuthali Ahmed H. , Datta-Gupta Akhil , Yuen Bevan , Fontanilla Jerry P. 
Published: July 2010

SummaryWaterflood optimization by means of rate control is receiving considerable attention because of increasing deployments of smart well completions and i-field technology. The use of inflow control valves (ICVs) allows us to optimize the production/injection rates of various segments along the wellbore, thereby maximizing sweep efficiency and delaying water breakthrough. Field-scale rate-optimization problems, however, involve highly complex reservoir models, production and facility constraints, and a large number of unknowns. In this paper, we propose an approach that is computationally efficient and suitable for large field cases. It is based on our previous work (Alhuthali et al. 2007, 2008), which relies on equalizing arrival time of the waterfront at all producers to maximize the sweep efficiency. We use streamlines to efficiently and analytically compute the sensitivity of the arrival times with respect to well rates. We also account for geologic uncertainty by means of a stochastic optimization framework using multiple realizations. Analytical forms for gradients and Hessian of the objective functions are derived, making our optimization computationally efficient for large-scale applications. Finally, optimization is performed under operational and facility constraints using a sequential quadratic programming approach.We demonstrate our approach using two field-scale examples. The first is a synthetic example called "Brugge" field, a benchmark case based on a North Sea Brent-type field. The production optimization of this field is carried out as part of a closed-loop process where the production history is matched prior to the production optimization. The production optimization is performed over multiple realizations for 20 years and involves 30 wells equipped with three ICVs per well. The second example is a super-giant Middle Eastern field that has more than 50 years of historical oil production. The optimization is performed for 20 years on a portion of this field that contains nearly 300 wells consisting of conventional vertical and horizontal wells and smart horizontal wells. In both examples, multiple field-related constraints are imposed, such as the maximum well injection and production rates, the maximum allowable drawdown, restriction on high-water-cut wells, and voidage replacement for pressure maintenance. The results clearly demonstrate the viability of our approach and the benefits of optimal rate control, with a considerable increase in cumulative oil production and a substantial decrease in the associated water production.
Results of the Brugge Benchmark Study for Flooding Optimization and History Matching
Authors: Peters E. , Arts R. J. , Brouwer G. K. , Geel C. R. , Cullick S. , Lorentzen R. J. , Chen Y. , Dunlop K. N. B. , Vossepoel F. C. , Xu R. , Sarma P. , Alhutali A. H. , Reynolds A. C. 
Published: July 2010

Summary
In preparation for the SPE Applied Technology Workshop (ATW) held in Brugge in June 2008, a unique benchmark project was organized to test the combined use of waterflooding-optimization and history-matching methods in a closed-loop workflow. The benchmark was organized in the form of an interactive competition during the months preceding the ATW. The goal set for the exercise was to create a set of history-matched reservoir models and then to find an optimal waterflooding strategy for an oil field containing 20 producers and 10 injectors that can each be controlled by three inflow-control valves (ICVs). A synthetic data set was made available to the participants by TNO, consisting of well-log data, the structure of the reservoir, 10 years of production data, inverted time-lapse seismic data, and other information necessary for the exercise. The parameters to be estimated during the history match were permeability, porosity, and net-to gross- (NTG) thickness ratio. The optimized production strategy was tested on a synthetic truth model developed by TNO, which was also used to generate the production data and inverted time-lapse seismic. Because of time and practical constraints, a full closed-loop exercise was not possible; however, the participants could obtain the response to their production strategy after 10 years, update their models, and resubmit a revised production strategy for the final 10 years of production. In total, nine groups participated in the exercise. The spread of the net present value (NPV) obtained by the different participants is on the order of 10%. The highest result that was obtained is only 3% below the optimized case determined for the known truth field. Although not an objective of this exercise, it was shown that the increase in NPV as a result of having three control intervals per well instead of one was considerable (approximately 20%). The results also showed that the NPV achieved with the flooding strategy that was updated after additional production data became available was consistently higher than before the data became available.
Thermal Streamline Simulation for Hot Waterflooding
Authors: Zhu Z.. , Gerritsen M.G.. G. , Thiele M.R.. R. 
Published: July 2010

Summary
We explore the extension of streamline simulation to thermal-recovery processes. For each global timestep, we first compute the pressure field on an Eulerian grid. We then solve for the advective parts of the mass balance and energy equations along the individual streamlines. At the end of each global timestep, we account for the nonadvective terms of the transport equations on the Eulerian grid along with gravity, using the operator splitting method. We included temperature-dependent viscosity and account for thermal expansion of the fluids. We tested our streamline simulator on 2D heterogeneous quarter five-spot problems and compared the results with those computed by a commercial thermal simulator both for accuracy and computational efficiency. We present sensitivity studies for effects of fluid compressibility, gravity, and thermal-conductivity. For the cases investigated, our thermal streamline simulator is capable of producing accurate results at a computational cost that is significantly lower than that of existing Eulerian simulators.
Natural and Conventional Tracers for Improving Reservoir Models Using the EnKF Approach
Authors: Huseby Olaf , Valestrand Randi , Nœvdal Geir , Sagen Jan 
Published: July 2010

Summary
Natural tracers (geochemical and isotopic variations in injected and formation waters) are a mostly unused source of information in reservoir modeling. On the other hand, conventional interwell tracer tests are an established method to identify flow patterns. However, they are typically underexploited, and tracer-test evaluations are often performed in a qualitative manner and are rarely compared systematically to simulation results. To integrate naturaland conventional-tracer data in a reservoir-modeling workflow, we use the ensemble Kalman filter (EnKF), which has recently gained popularity as a method for history matching. The EnKF includes online update of parameters and the dynamical states. An ensemble of model representations is used to represent the model uncertainty. In this paper, we include conventional water tracers as well as natural tracers (i.e., geochemical variations) in the EnKF approach. The methodology is demonstrated by estimating permeability and porosity fields in a synthetic field case based on a real North Sea field example. The results show that conventional tracers and geochemical variations yield additional improvement in the estimates and that the EnKF approach is well suited as a tool to include in this process. The principal benefit from the methodology is improved models and forecasts from reservoir simulations, through optimal use of conventional and natural tracers. Some of the natural-tracer data (e.g., scale-forming ions and toxic compounds) are monitored for other purposes, and exploiting such data can yield significant reservoir-model improvement at a small cost.
Misconceptions Regarding the Chemical Role of Completion/Packer Fluids in Annular Environmentally Assisted Cracking of Martensitic Stainless Steel Tubing
Authors: McKennis Jeffrey S. , Sook-Bae Nam , Termine Enrico J. , Shimamoto Ken , Kimura Mitsuo 
Published: July 2010

Summary
The increased use of corrosion resistant alloys (CRAs) in deep high-pressure/high-temperature (HP/HT) wells has led to production-tubing cracking failures throughout the industry. Many of these failures have occurred from the outside (annulus side) and have been attributed to environmentally assisted cracking (EAC) and, hence, are best described as annular EAC (AEAC). Examination of these failures points to a serious incompatibility of the production tubing metallurgy with the packer fluid under stress.
In 2003, combining expertise in fluid chemistry and metallurgy, the authors formed a research alliance to address the AEAC problem by examining the compatibility of a wide spectrum of completion fluids with various martensitic stainless steel (MSS) metallurgies. This unique research collaboration, involving extensive stress-cracking testing performed with different metallurgies and different fluids under simulated well conditions, has resulted in an extensive database (more than 4,000 test entries for 27 fluids and six MSS metallurgies) and a new body of knowledge regarding the causes behind AEAC failures.
Conventional wisdom holds that chloride ion and oxygen play major causative roles. The authors’ findings, however, identify other contaminants in completion/packer fluids that play the dominant role in the chemical mechanism of the crack failures. Such contaminants include sulfur-containing species, oxidants other than oxygen, and select basic ionic species. This paper addresses the effect of the new information and identifies serious misconceptions regarding the role of completion /packer fluids in the tubular failures.
The authors’ comprehensive study has advanced the industry's knowledge of the causes of AEAC by detailing the previously unrecognized importance of various contaminants present in the fluids. As a consequence, the need for quality assurance and best- practice fluid management throughout the life cycle of the fluids is now recognized. Misconceptions with respect to the chemical mechanisms and causative factors of AEAC failures are discussed. Such information should expand the industry's AEAC knowledge base and minimize the risk of tubular failure.
Quantitative Evaluation of Calcium Sulfate Precipitation Kinetics in the Presence and Absence of Scale Inhibitors
Authors: Fan Chunfang , Kan Amy T , Fu Gongmin , Tomson Mason B , Shen Dong 
Published: July 2010

Summary
In this study, the nucleation kinetics of calcium sulfate scale formation in the presence and absence of scale inhibitors has been studied. The nucleation kinetics of calcium sulfates in 0–3.2 M NaCl solution was measured from 0 to 200°C at various supersaturation conditions [saturation index (SI) = 0–1.3]. The phase behavior of these various calcium sulfate phases was monitored by X-ray diffraction (XRD). The inhibition study was performed by evaluating the inhibition efficiency of calcium sulfate precipitation at the same supersaturation and temperature ranges as those of the nucleation study. Several polyphosphonate, polymeric, and environmentally friendly inhibitors were found to be effective inhibitors. The study has shown that calcium sulfate scales are very difficult to inhibit at SI &gt; 1. Calcium sulfate scale is inhibited most effectively by hexamethylenediamine tetra(methylene phosphonic acid) (HDTMP) if the saturation index is less than approximately 1.0. In addition, a semiquantitative model to predict precipitation kinetics of calcium sulfate as a function of temperature, pH, SI, and HDTMP concentration is established with experimental results from this study. The effect of methanol and methylene glycol (MEG) on calcium sulfate precipitation kinetics and inhibition is also presented.
Design of a High-Pressure Research Flow Loop for the Experimental Investigation of Liquid Loading in Gas Wells
Authors: Fernandez J.. , Falcone G.. , Teodoriu C.. 
Published: July 2010

Summary
Existing models to predict and analyze liquid loading in gas wells are based on steady-state flow. Even when transient-multiphase- wellbore models are employed, steady-state or pseudosteady-state inflow-performance relationships are used to characterize the reservoir. A more-reliable approach consists of modeling the dynamics in the near-wellbore region with its transient boundary conditions for the wellbore. The development of new models to mimic the dynamic interaction between reservoir and wellbore requires a purpose-built flow loop. We have developed a design to construct such a facility.
This new facility will be the first to integrate pipe representing the wellbore with a porous medium that will fully mimic the formation surrounding the wellbore. This design will account not only for flow into the wellbore, but also for any reverse flow from the pipe into the medium.
We used integrated wellbore/reservoir system analysis to screen the parameters required to recreate liquid loading under laboratory conditions. Our results suggested using a compressed-air system with a discharge pressure between 470 and 650 psi with gas rates of 400 to 650 scf/min along with water injected at a rate of 100 gal/min. Once the range in operating conditions was defined, the equipment and mechanical components for the facility were selected and designed.
Our results showed that three reciprocating compressors working in parallel provide the smallest, most economic, and most flexible configuration for the TowerLab facility at Texas A&M University (TAMU). The design of the pressure vessel hosting the porous medium will require a cylindrical body with top- and bottom-welded flathead covers with multiple openings to minimize weight. The required superficial velocities for air and water indicate the system will need independent injection into the porous medium through two manifolds. Optimally, the system will use digital pressure gauges, coriolis or vortex technology to measure air flow, and turbine meters for water flow.
A joint-industry project (JIP) on liquid loading in gas wells was initiated in January 2009, which includes the implementation of the proposed design for the TowerLab facility to generate experimental data that will significantly improve our ability to mimic the physics of multiphase flow, and so develop and validate flow models for the characterization of liquid loading in gas wells. It is anticipated that a preliminary version of the new loop, including an inlet multiphase-flow pump, has been assembled and will be operational early in Fall 2010, with plans for the full design to be implemented in 2010-11.
Integration of Well-Test Pressure Data Into Heterogeneous Geological Reservoir Models
Authors: Li Gaoming , Han Mei , Banerjee Raj , Reynolds Albert C. 
Published: July 2010

Summary
This paper presents the application of the ensemble Kalman filter (EnKF) method to the integration of well-test data into heterogeneous reservoir models generated from geological and geophysical data. EnKF does not require computing the gradient of an objective function and, hence, can be applied easily with any reservoir simulator, and more importantly, it is far more efficient than a gradient-based history-matching procedure when the forward model is represented by a reservoir simulator. In the procedure for integrating pressure-transient data considered here, the static geological/geophysical data are assumed to be encapsulated in a multivariate probability-density function (pdf) characterized by a prior mean and covariance for the joint distribution of the porosity and permeability fields. Because the prior mean of the property fields obtained from the core and log data can sometimes be erroneous, a partially doubly stochastic model is applied to account for the uncertainty of the prior mean. In the doubly stochastic model, a correction to the prior mean is adjusted together with the heterogeneous field during history matching. The method is tested with synthetic heterogeneous single-layer and two-layer reservoirs. Excellent data matches are obtained with EnKF in a small fraction of the time that would be required for a gradient-based history-matching process, and the observed data fall within the uncertainty bounds of the ensemble data predictions. In the layered-reservoir case, the uncertainty in rock-property fields is reduced further by integration of production-log data (layer flow rates). We show that problems of statistical inconsistency and poor data matches that are sometimes encountered when matching production data with EnKF do not occur when matching pressure data with the EnKF implementation used here. This undoubtedly occurs because the dynamical system (reservoir-simulator equations) is much more nearly linear for the single-phase-flow problems considered here than for multiphase-flow cases.