bluuebunny/crossref_metadata_2025_split huggingface dataset:
Dynamic Simulation and Control-System Design for Gas/Liquid Cylindrical Cyclone Separators
Authors: Wang S. , Mohan R. S. , Shoham O. , Kouba G. E. 
Published: December 2007

SummaryGas/Liquid Cylindrical Cyclone (GLCC, copyright, the U. of Tulsa, 1994) separator performance can be improved considerably by adopting a suitable control strategy to reduce liquid carry-over into the gas stream or gas carry-under into the liquid stream. A dynamic model for control of GLCC liquid level and pressure with classical control techniques is developed in this paper for the first time. Detailed analysis of the GLCC control-system stability and transient response indicates that liquid-level control can be achieved effectively by a control valve in the liquid outlet for gas-dominated systems or by a control valve in the gas outlet for liquid-dominated systems. Based on the proposed linear-control system model, the system performance is simulated with a suitable software design tool. Experimental investigations have been conducted to evaluate the liquid-level and pressure-control systems. The novel control-system design approach presented in this paper forms a framework for the GLCC active control-system optimization.
Reservoir Modeling Using Scale-Dependent Data
Authors: Panda M. N. , Mosher C. , Chopra A. K. 
Published: December 2007

SummaryA reservoir description incorporating the precision and scale of all available data (geological, petrophysical, seismic, tracer, and well-test data) is critical for reservoir modeling. The heterogeneous variables sampled by these data are composed of several superimposed functions, each characterized by a unique spatial and temporal scale or support. For example, core, well-log, well-test, and seismic data have supports ranging from inches to thousands of feet.Current geostatistical methods map lithofacies, porosity, and permeability on a network of grid nodes called the geologic modeling cells. Pseudopoint properties that assimilate information from all available data are modeled onto model cells using one of several available conditional-simulation techniques. Some methods attempt to combine data with varying support, and data with multiple-scale support, through simple correlations. For example, one approach to incorporate geophysical data is to use a direct transform of the seismic signal to rock properties through a linear regression or crossplot. Reservoir models built using such linear correlations tend to be case-specific with little generality.This paper presents a method for identifying the impact of multiscale data (data that measure average property over multiple-flow units) on reservoir modeling. It examines the information about the reservoir system each data type carries, for example, what fraction of core scale variability is captured by well-log data. We also present a consistent method for integrating multiscale data. Through a series of numerical simulations, we show the impact of reservoir-property heterogeneity on the fluid-flow performance.
Behavior of the Bagnore Steam/CO2 Geothermal Reservoir, Italy
Authors: Atkinson P. G. , Celati R. , Corsi R. , Kucuk F. 
Published: December 2007

Abstract
A commonly encountered geothermal steam reservoir consists of a gas cap overlying an aquifer. In addition to steam, the gas cap may contain substantial amounts of carbon dioxide and other noncondensable gases. A mathematical model for describing the pressure and composition histories of such reservoirs is presented. The model evaluates the change in states of a homogeneous vapor/liquid region as a mixture of steam and carbon dioxide is removed from the gas cap and as recharge water enters the liquid region.
The production history of the Bagnore steam field in Italy was evaluated using this model. It is concluded that early reservoir behavior was controlled by a blowdown of carbon dioxide in the gas cap, while long-time behavior is being controlled by water influx.
Control Model of Water Injection Into a Layered Formation
Authors: Silin D. B. , Patzek T. W. 
Published: December 2007

Summary
Here we develop a new control model of water injection from a growing hydrofracture into a layered soft rock. We demonstrate that in transient flow, the optimal injection pressure depends not only on the instantaneous measurements, but also on the whole history of injection, growth of the hydrofracture, and the rock damage. Based on the new model, we design an optimal injection controller that manages the rate of water injection in accordance with hydrofracture growth and the formation properties. We conclude that maintaining the rate of water injection into a low-permeability rock above a reasonable minimum inevitably leads to hydrofracture growth, to establishment of steady-state flow between injectors and neighboring producers, or to a mixture of both. Analysis of field water injection rates and wellhead pressures leads us to believe that direct links between injectors and producers can be established at early stages of waterflood, especially if the injection policy is aggressive. Such links may develop in thin, highly permeable reservoir layers or may result from failure of the soft rock under stress exerted by injected water. These links may conduct a substantial part of injected water. Based on the field observations, we now consider a vertical hydrofracture in contact with a multilayer reservoir, where some layers have high permeability and quickly establish steady-state flow from an injector to neighboring producers.
The main result of this paper is the development of an optimal injection controller for purely transient flow, and for mixed transient/steady-state flow in a layered formation. The objective of the controller is to maintain the prescribed injection rate in the presence of hydrofracture growth and injector/producer linkage. The history of injection pressure and cumulative injection, along with estimates of the hydrofracture size, are the controller inputs. By analyzing these inputs, the controller outputs an optimal injection pressure for each injector. When designing the controller, we keep in mind that it can be used either offline as a smart adviser, or online in a fully automated regime.
Because our controller is process model-based, the dynamics of actual injection rate and pressure can be used to estimate effective area of the hydrofracture and the extent of the rock damage. The latter can be passed to the controller as one of the inputs. Finally, a comparison of the estimated fracture area with independent measurements leads to an estimate of the fraction of injected water that flows directly to the neighboring producers through links or thief-layers.
Current Steamflood Technology
Authors: Ali S.M. Farouq , Meldau R.F. 
Published: December 2007

This paper provides an overview of current steam injection technology. Reservoir data and performance are compiled for 13 selected field projects in the U.S., Canada, and Venezuela. Subjects discussed include oil recovery, well completions, operating practices, and special reservoir conditions. Emphasis is on steamflooding, with some data on cyclic steam stimulation.

Introduction
The purpose of this paper is to help petroleum engineers keep up with emerging steamflood technology, including both reservoir and operating experience. Useful data and references also are provided. provided. Steam injection is the principal enhanced oil-recovery method used today, accounting for 90% of all oil produced by such methods. Prats estimates the total worldwide oil production rate from steam is about 400,000 BOPD (64 000 ml/d oil). The U.S. produces 60% of this total, Venezuela produces produces 60% of this total, Venezuela produces 35%, and Canada produces 3%. Several large projects are in the planning and construction stages projects are in the planning and construction stages for the oil sands of Alberta and the Orinoco oil belt of Venezuela .Steam injection technology has advanced significantly since the status of steam injection was reviewed at a Canadian Inst. of Mining and Metallurgy meeting 6 years ago. The Oil and Gas J.'s annual review for 1978 lists 99 active steam-injection projects for the U.S., 41 for Venezuela, and 14 for Canada . In addition, petroleum engineers have published several technical papers describing field projects and providing greater understanding of how the process can best be applied in the future.The most notable development in steam injection during the past 5 years is the overwhelming shift to steamflooding, with cyclic steam stimulation becoming an important adjunct, rather than a separate oil-recovery process. This is attributed (1) to the relatively low recovery oil recovery attainable by cyclic steam stimulation and (2) to higher oil prices, which have served to make economically attractive the considerably lower oil/steam ratios characteristic of steamfloods.

Field Tests
Table 1 gives formation characteristics and Table 2 lists test results for 13 selected steam-injection field tests. These tests represent most of the major steam-injection projects, except for those reported earlier in Refs. 5 and 6. Unfortunately, a few large projects are not listed in Table 1 because sufficient data were not available. These include Santa Fe Energy Co. Chanslor Div.'s 23,000-BOPD (3700-m3/d oil) Midway-Sunset project, Texaco Inc.'s 35,000-BOPD (5600-m3/d oil) San Ardo project, and several steamfloods in Venezuela. Test 4 (Charco Redondo) is cited in Table 1 primarily because of its unique features. This project was a highly instrumented steam pilot in a thin, waterflooded reservoir. Following the steamflood, the field was flooded successfully by in-situ combustion. Tests 6 and 13 are large, cyclic steam-stimulation projects, and the rest are steamfloods.
JPT
P. 1332
Optimizing Gas-Storage Reservoir Performance
Authors: McVay D. A. , Spivey J. P. 
Published: December 2007

Summary
As gas storage becomesincreasingly important in managing the nation's gas supplies, there is a need to develop more gas-storage reservoirs and to manage them more efficiently. Using computer reservoir simulation to rigorously predict gas-storage reservoir performance, we present specific procedures for efficient optimization of gas-storage reservoir performance for two different problems. The first is maximizing working gas volume and peak rates for a particular configuration of reservoir, well, and surface facilities. We present a new, simple procedure to determine the maximum performance with a minimal number of simulation runs. The second problem is minimizing the cost to satisfy a specific production and injection schedule, which is derived from the working gas volume and peak rate requirements. We demonstrate a systematic procedure to determine the optimum combination of cushion gas volume, compression horsepower, and number and locations of wells. The use of these procedures is illustrated through application to gas-reservoir data.
Treating Reinjected Oilfield Brine By Microbial Clarification
Authors: Philippovich N. A. , Winter J. 
Published: December 2007

Summary
Rising water volumes and processing costs in the oil field have spurred OMV to look for alternatives to traditional water processing. Despite an elaborate central multistep water-treating system, increasing injection pressures, water fouling in the pipelines, and reservoir souring were noticed. In a five-year program involving field measurements, laboratory experiments, the construction of a pilot facility, and test injections, a new strategy was adopted. The central water-conditioning plant (WCP) has been revamped. Instead of biocide addition, removal of organic nutrients by a biological clarification step now produces a clear, well injectable, and stable injection water.
Integration of Geology, Geophysics, and Numerical Simulation in the Interpretation of a Well Test in a Fluvial Reservoir
Authors: Raghavan R. , Dixon T. N. , Phan V. Q. , Robinson S. W. 
Published: December 2007

SummaryThe focus of this paper is the incorporation of geologic and geophysical data in the analysis of pressure tests in a fluvial reservoir. Using a 3,105,851-cell "porosity cube" derived by seismic and well-log data, this work outlines the steps involved in developing a 3D model with 7,128 cells that was used to estimate reservoir properties (such as permeability, skin, permeability/porosity relationship, reservoir connectivity, and fault factor). The principal steps involved in developing the reservoir model include:identifying all points in the porosity cube that were connected to the wellbore, with porosities above a specified cutoff to identify high-porosity channels and low-porosity overbanks, upscaling the porosity cube to a reasonable size for well-test simulation while preserving pay thickness, pore volume, and connectivity between high- and low-porosity materials; and matching the observed pressure and pressure-derivative responses with a numerical simulator and a regression program to automatically adjust the reservoir permeability description.A well test in a gas-condensate reservoir is used to demonstrate the ideas outlined in this work. This approach allowed us to identify not only horizontal permeability but also vertical permeability. The issues that need to be considered and the conclusions that are derived on the basis of this work differ significantly from conventional interpretations.
Effect of Pore-Lining Chlorite on Petrophysical Properties of Low-Resistivity Sandstone Reservoirs
Authors: Durand Claudine , Brosse Etienne , Cerepi Adrian 
Published: December 2007

SummaryChlorite-bearing sandstones usually give low resistivity signals and are thus erroneously identified as nonpay zones, even if they exhibit good preserved porosities at depth. The purpose of this paper is to provide petrophysical and mineralogical laboratory measurements that help improve the log interpretation of these sandstones.The main results were obtained from a selection of reservoir cores. For sandstones having an amount of chlorite between 3 and 11 wt%, they show that the cementation index and saturation exponents (m and n) have values lower than 2, with n frequently around 1.5. These low values have been checked carefully to avoid experimental artifacts. Cationic Exchange Capacities (CEC) and Specific Surface Areas (SSA) both have low values, as expected from the clay structure. The distribution of pore throats is bi- or tri-modal, with a large contribution of microporosity.The interpretation suggested by these results is that the amount and distribution of microporosity associated with pore-lining clay is the key to the chlorite sandstone electrical behavior. The values of CEC or SSA are too low to fully explain the low values of the saturation index n.Use of these low values in log interpretation has the effect of increasing the interpreted oil in place. Advantages of a multidisci-plinary approach for better evaluation of such complex argillaceous sandstone reservoirs is highlighted.
Delineating the Pour Point and Gelation Temperature of Waxy Crude Oils
Authors: Venkatesan Ramachandran , Singh Probjot , Fogler H. Scott 
Published: December 2007

Summary
Paraffin deposition in subsea pipelines is a multimillion-dollar problem in the oil industry. The temperature at which a waxy crude oil gels is an important property that determines the initiation of the deposition process. The "pour point," as defined by the standard ASTM test method, is not sufficient to describe the deposition of waxy crudes under flow conditions. The "gelation temperature," explained in this article, is found to be an appropriate measure of the onset of gelation under static as well as flow conditions. Rheological experiments show that the gelation temperature of a wax-oil system is depressed by the shear stress acting on the system during cooling.
Design, Fabrication, and Installation of the Ninian Field Southern Platform
Authors: Hancock M.V. , Nay M.C. , White E.I. 
Published: December 2007

In an effort to eliminate problems previously experienced in fabrication and installation of large steel structures, emphasis for the Ninian field southern platform was placed on designing for those factors as well as for functional and long-term loadings. This paper describes design and innovative features of the structure.

Introduction
Chevron's Ninian field southern platform is noteworthy for its rapid planning, design, fabrication, and extremely successful installation, all of which justified the conceptual philosophy adopted early in the design stage. The aim was to build on past experience and to provide simplicity and refinement within the limits of available technology, consistent with a summer 1977 installation of a platform capable of supporting the heaviest deck load yet proposed for a piled steel structure. These goals, together with severe functional and environmental criteria, resulted in a number of interesting features.This paper describes the process leading to the selection of a self-floating steel tower and outlines the manner in which considerations of fabrication, transportation, and installation influenced the configuration of structure and piles.

Selection of Platform Type, Factors Influencing Configuration
It was believed that the success of the proposed program would rely as much on designing for fabrication and installation requirements as on structural analysis and design. In the overall development cost, the effect of saving structural steel weight by virtue of exhaustive analytical work is insignificant; on the other hand, time spent on designing for fabrication and installation can result in significant cost savings.

Description of Tower
The Ninian field southern platform is a four-leg, piled, steel-tower structure supporting modular production and drilling facilities (Fig. 1). It is a self-floating unit with an integral ballasting system designed for remote-controlled operation.The deck comprises two levels of modules, 65 × 68 m in plan, providing three main levels, with a nominal production capacity of providing three main levels, with a nominal production capacity of 150,000 BOPD. Maximum anticipated deck load is 26 000 t, including two drill rigs. Slots are provided for 42 conductors.Typical dimensions are 75 × 75 m center to center of the legs at the mudline, tapering to 55 × 55 m at the top of the module support skid beams. Overall height from mudline to skid beams is 168.5 m.The tower is supported by 32 skirt piles, 1825 mm OD with walls 63 mm thick, arranged in clusters of eight at each leg in a 12.2-m diameter circular pattern.Storage is provided in the upper parts of the 9.2-m diameter flotation legs for 20,000 bbl of diesel fuel and 10,000 bbl of drilling water.
JPT
P. 1366
High-Density Monomer System for Formation Consolidation/Water-Shutoff Applications
Authors: Eoff Larry , Funkhouser Gary P. , Cowan Mike 
Published: December 2007

Summary
This paper describes an in-situ polymerizable organic monomer hydrogel system for formation consolidation during deepwater drilling applications in which a water-soluble vinyl monomer solution is polymerized in-situ to seal and consolidate unstable geological zones. In deepwater wells, shallow zones may have pore pressures close to parting pressures. In these situations, lost circulation or flowing zones can be difficult to control and can lead to a complete loss of the well.
Hydroperoxide and azo initiators are used for polymerizing solutions of 2-hydroxyethyl acrylate monomer in aqueous solutions of synthetic seawater, sodium chloride (NaCl), calcium chloride (CaCl2), calcium bromide (CaBr2), and zinc bromide (ZnBr2), with densities from 8.6 to 17.5 lbm/gal. These monomer solutions undergo controlled polymerizations in the formation to yield a crosslinked hydrogel matrix that can withstand high differential pressures. A similar monomer system has been used for water-shutoff applications but had never been formulated in heavy brines or used in the cool temperatures (50 to 60°F) typical of the shallow water-flow zones. The use of a high-density hydrogel for consolidation purposes would be an advantage in shallow water-flow zones because the gelant solution of the hydrogel could be spotted over, and allowed to flow into, the problem zone where the gelant flow is driven by the hydrostatic pressure of the treatment fluid. This process enables the use of the monomer system in wells where high-pressure injection of the treatment fluid into the formation is not an option.
This article describes the hydrogel system's development, including gel-time curves and compressive strengths of consolidated sandpacks, and discusses factors affecting the performance and application of the system.
Deepwater Tie-Ins of Rigid Lines: Horizontal Spools or Vertical Jumpers?
Authors: Corbetta Giovanni , Cox David S. 
Published: December 2007

Summary
Movement toward deeper waters and harsher environmental conditions has required the continuous development of new technologies, and will continue to do so. In particular, this need has manifested itself in the design and operation of remote tooling to complete subsea field developments.
One of the principal problems faced during both the design and operational phases of a project is the definition of methods and systems to perform the tie-in of production lines to subsea facilities. This problem, in fact, influences some critical decisions such as the type of lines used (rigid/flexible), the structure layout (tie-in porches and interfaces), and the method of installation (first- or second-end connections).
Different systems to perform remote connections of either flexible or rigid lines have been developed. Among these, special attention was paid to rigid line connections, which are the preferred option of the industry for both technical and economic reasons. This new focus has, in turn, led to the development of systems able to perform tie-ins of rigid lines using either horizontal spools or vertical jumpers. This paper presents a comprehensive comparison between these two methods, including an overview of the systems considered and an outline of advantages and drawbacks, both technical and financial, of the two solutions.
A Geostatistical Approach to Streamline-Based History Matching
Authors: Caers Jef , Krishnan Sunderrajan , Wang Yuandong , Kovscek Anthony R. 
Published: December 2007

Summary
History matching large reservoir models under a realistic geological continuity constraint remains an outstanding problem. We propose a new combined geostatistical and streamline-based method potentially capable of history matching large reservoir models, while accounting consistently for geological continuity as provided by a permeability histogram and variogram and by production data. While most existing history-matching techniques somehow rely on the calculation of single-gridblock sensitivity coefficients, the proposed method avoids such calculation entirely by perturbing jointly effective permeabilities along a set of streamlines. Such perturbation results in large changes of the permeability field that reduce significantly error in each iteration of the history-matching procedure. The problem of mapping streamline effective permeability perturbations to single gridblocks is performed under a Gauss-Markov random function constraint. This novel stochastic mapping procedure accounts for the target histogram and variogram while honoring the streamline effective permeability perturbations. Forward flow simulation is achieved by a streamline simulator. The methodology is presented on synthetic cases; it appears to be computationally efficient and robust.