bluuebunny/crossref_metadata_2025_split huggingface dataset:
Designing Multistage Frac Packs in the Lower Tertiary Formation–Cascade and Chinook Project
Authors: Haddad Ziad , Smith Mike , De Moraes Flavio Dias 
Published: April 2012

Summary
The Cascade and Chinook Project is located in the Walker Ridge area in the Gulf of Mexico (GOM), 250 miles south of New Orleans in depths between 8,200 and 8,900 ft. The oil-producing reservoir is in the Lower Tertiary Wilcox formation, with a gross sand thickness of 1,200 ft. The reservoir midpoint is at an average depth of 25,600 ft true vertical depth subsea (TVDss), with a bottomhole pressure of 19,500 psi and a bottomhole temperature of 260°F. The reservoir comprises vertically stacked thin beds of sand and fine-grained-siltstone intervals with effectively no vertical permeability. Additional information on this project can be found in Moraes et al. (2010).
Multiple limitations were considered during the initial design phase of the frac-pack program. The fracs were designed taking into account the use of a single-trip multizone (STMZ) sand-control system. Some of these design challenges are briefly discussed by Cunha et al. (2009). Although this system was not crucial in the overall implementation of the frac program, it added additional complexity from an operational standpoint because of a continuous, multistage frac operation. Some of the operational limitations included service-tool erosion limitations because of maximum pump rates and proppant volumes, overall frac-vessel capacity, boat-to-boat fluid transfers, and crew fatigue. The geological complexities of the reservoir were another major challenge in completing this very thick interval. Perforation intervals had to be placed to avoid a fault (and thus a potential early screenout), avoid a water contact, comply with tool-spacing limitations, and still maximize contact with net pay.
This paper addresses the approach taken to develop a fracture-stimulation program for the Lower Tertiary formation in the Cascade and Chinook Project. Some of the major questions addressed during this process include the following: How many fracture treatments are needed? What is the optimum fracture geometry? What is the desired conductivity? How to effectively position the perforation intervals? What is the desired pump rate, and is a high-density fluid needed to fracture this deep, high-pressure formation? The approach, the answers, and the treatment are discussed along with responses to additional questions that arose during the actual fracturing operations.
Along with the Lower Tertiary in the GOM, the industry faces similar challenges around the world. These include reservoirs with potentially large reserves but much lower permeability (caused by depth and in-situ stresses) where fracturing is required for both stimulation and potential formation-collapse sand control. Careful planning is necessary to avoid costly learning curves in these environments.
Gas Lift Optimization Using Proxy Functions in Reservoir Simulation
Authors: Lu Q.. , Fleming G.C.. C. 
Published: April 2012

Summary
Artificial lift by means of gas injection into production wells or risers is frequently used to increase hydrocarbon production, especially when reservoir pressure declines. We propose an efficient optimization scheme that finds the optimal distribution of the available gas lift gas to maximize an objective function subject to surface-pipeline-network rate and pressure constraints. This procedure is a nonlinearly constrained optimization problem solved by the generalized reduced-gradient (GRG) method. The values of objective function, constraint functions, and derivatives needed for optimization can be evaluated through two methods. The first method repeatedly solves the full-network equations using Newton iteration, which takes into account the flow interactions among wells; however, this method can be computationally expensive. The second and more efficient method is a new approach proposed in this paper. It constructs a set of proxy functions that approximates the objective function and constraints as functions of gas lift rates. The proxy functions are obtained by solving part of the network that consists of a gas lifted well or riser, assuming a stable pressure at the terminal node where the partial network is decoupled from the rest of the network, and are used to inexpensively evaluate the objective function, constraints, and necessary derivatives for the optimizer. A procedure to predict the proxy functions on the basis of previous values can be used to reduce the number of partial-network solves, and the partial-network solution has been parallelized for faster simulation. These two methods can be applied at different timesteps during the course of the simulation. The proposed methods are implemented within a general-purpose black-oil and compositional reservoir simulator and have been applied to real-field cases.
Chemical Modification of Biopolymers To Design Cement Slurries With Temperature-Activated Viscosification—A Laboratory Study
Authors: Reddy B.R.. R. , Patil R.. , Patil S.. 
Published: April 2012

Summary
Polymeric viscosifiers are added to cement slurries for a variety of reasons, including prevention of particle settling and control of fluid loss, gas migration, and free water. Many of these functions are critically important after the cement slurry has been placed behind the casing but before the setting of the cement. Some functions, such as particle-settling prevention, are also important during the pumping phase. Unfortunately, most of the viscosifying polymers suffer from thermal thinning at bottomhole temperatures, especially under shear. The amount of polymer required to maintain the required level of viscosity at elevated bottomhole temperatures causes excessive surface-slurry viscosification at ambient temperature. Pumping such slurries can require higher pump pressures, which, in some cases, might exceed formation breakdown pressures causing unintended fractures.This becomes a serious challenge when the window between the fracture pressure and the pore pressure of the formation is narrow. It would be a significant improvement to oilfield cementing technology to develop polymers that do not cause excessive slurry viscosification on the surface but gradually increase the slurry viscosity as it reaches downhole temperatures, with the maximum viscosity reached at the time the slurry becomes static behind the casing.
This paper describes a chemical method, not based on encapsulation, for modifying biopolymers and their derivatives—for example, hydroxyethylcellulose (HEC) and xanthan—that renders them insoluble in cement slurries at room temperature (RT). When the cement slurries containing modified HEC are heated, the slurries develop viscosity upon heating, as reflected by changes to slurry rheology with temperature. The method also provides for increased viscosification efficiency of the modified polymers because of the increased molecular weights of the modified biopolymer products. Synthesis details, slurry rheologies at different temperatures, and job-placement simulation details are presented. A possible reaction mechanism that is operative in the chemical-modification step is also discussed.
Shear Stability of EOR Polymers
Authors: Zaitoun A.. , Makakou P.. , Blin N.. , Al-Maamari R.S.. S. , Al-Hashmi A.R.. R. , Abdel-Goad M.. , Al-Sharji H.H.. H. 
Published: April 2012

Summary
An experimental study of shear stability of several high-molecular-weight polymers used as mobility-control agents in EOR projects has been performed in well-controlled conditions. The shearing device was made of a capillary tube with an internal diameter (ID) of 125 μm, through which polymer solution was injected at a controlled rate. The setup enables a precise measurement of the shear rate to which the polymer macromolecule is submitted. The degradation rate was measured by the viscosity loss induced by the passage into the capillary tube. The shear rate was gradually increased up to 106 sec–1 while checking degradation rate at each stage.
Different commercial EOR polymer products were submitted to the test with polyacrylamide backbone and different substitution monomer groups. All macromolecules behave as flexible coils in solution. The parameters investigated were Molecular weight (between 6 and 20×106)Nature of substitution group (acrylate, ATBS/sulfonate, nVP/ vinyl-pyrrolidone)Salinity Polymer shear degradation increases with molecular weight and salinity, but decreases with the presence of acrylate, ATBS, and nVP. All results can be interpreted in terms of chain flexibility. The highly flexible polyacrylamide homopolymer is the most sensitive to shear degradation. Introduction of acrylate groups in the polymer chain induces some stability because of the rigidity provided by charge repulsion, which vanishes in the presence of high salinity because of the screening of acrylate negative charges. ATBS and VP groups, which are larger in size, provide significant chain rigidity, and thus better shear stability. It is also shown that some very-high-molecular-weight polymers, after passing the shearing device, attain a final viscosity lower than lower-molecular-weight products with the same chemical composition. This factor has to be taken into account in the final choice of a polymer for a given field application.
As a comparison, although less popular today than 2 decades ago, xanthan gum (XG), which behaves like a semirigid rod, is shown to be much less sensitive to the shear-degradation test than the coiled polyacrylamides (Sorbie 1991).
Reduction of Perforating Gunshock Loads
Authors: Baumann C.E.. E. , Guerra J.P.. P. , William A.. , Williams H.A.. A. 
Published: April 2012

Summary
Thousands of well-perforation jobs are executed successfully around the world each month; however, certain perforation jobs require special design considerations to minimize the risk of equipment damage, such as bent tubing and unset packers, from perforating gunshock loads. Perforating guns generate pressure waves in the completion fluid and stress waves in structural components. The magnitude, duration, and timing of these waves depend on job parameters that can be adjusted by the design engineer, such as type, length, and loading of guns; number of shock absorbers; distance from sump packer to bottom of guns; and distance from completion packer to top of guns. The sensitivity of peak loads and gun-string movement to key design parameters can be evaluated with a software tool specifically developed to predict well-perforation-induced transient fluid-pressure waves and the ensuing structural loads. All relevant aspects of well-perforating events are modeled, including gun carrier filling after firing, wellbore pressure waves and associated fluid movement, wellbore pressurization and depressurization by reservoir pressure, and the dynamics of all relevant gun-string components, including shock absorbers, tubing, and guns.
Existing fast-gauge pressure data from a large number of perforation jobs were used in previous jobs to verify that predictions made by using software simulation are sufficiently accurate, both in magnitude and time; thus, the transient pressure loading on well components is sufficiently accurate to predict the structural dynamics response and the associated gun-string loads. In this paper, we present case studies that show how key elements used for gunshock mitigation are simulated, and the sensitivity of peak loads and deformation to gun-string elements, such as shock absorbers, gun types and loading, tubing size and weight, and packer placement.
With this software, we evaluate the dependence or sensitivity of peak loads and gun-string movement on/to key design parameters, and, when necessary, design changes are made to reduce potentially unsafe load conditions. The design verification and optimization methodology described in this paper significantly reduces the risk of nonproductive time and fishing operations. Key technologies described in this paper enabled the successful execution of many deepwater high-pressure (HP) perforation jobs, including Petrobras’ Cascade and Chinook, the largest deepwater HP perforation jobs performed to date in the Gulf of Mexico.
Controlled Use of Downhole Calcium Carbonate Scaling for Sand Control: Laboratory and Field Results on Gullfaks
Authors: Fleming N.. , Berge E.. , Ridene M.. , Østvold T.. , Jøsang L.O.. O. , Rohde H.C.. C. 
Published: April 2012

Summary
Gullfaks has been in production since 1986 and produces approximately 11 500 std m3/d of oil from three Condeep platforms. The average water cut is approximately 75 to 80% and gas/oil ratio (GOR) is approximately 200 std m3/std m3. It has been estimated that between 50 and 100 t of sand is produced yearly per platform, with approximately 60 to 70% of the wells in active production (approximately 90) limited by sand production. The typical well completion is cased hole with selective production through perforated liners. Rock-mechanics studies have shown that sand will be produced irrespective of well inclination and perforation design.
On Gullfaks, the sand-management strategy used has been to produce wells at "maximum" or "acceptable" sand rates. This strategy has led to significant gains in production, although there are challenges with this approach that include choke erosion, sand removal from the separators, and oil-in-water quality associated with discharge to sea. In response to this, Statoil has investigated different methods of retaining sand downhole by chemical sand consolidation, of which in-situ calcium carbonate (CaCO3) precipitation will form the basis for this paper. This technology involves squeezing into the near-wellbore formation predefined concentrations of urea and calcium nitrate along with the enzyme urease. After application, the well is shut in, during which the enzyme catalyzes the decomposition of urea to bicarbonate that reacts with calcium to form calcium carbonate.
This paper will provide details of the laboratory evaluation and, in particular, will focus on the field results from the first-ever application of this type. A low-risk candidate well was selected that had a short perforated interval (19 m) and produced 88 std m3/d oil with a water cut of 94%. Results of the operation design and planning, logistics examination, thorough risk evaluation, and post-operation results with lessons learned will be presented.
Thermally Active Polymer To Improve Sweep Efficiency of Waterfloods: Simulation and Pilot Design Approaches
Authors: Garmeh R.. , Izadi M.. , Salehi M.. , Romero J.L.. L. , Thomas C.P.. P. , Manrique E.J.. J. 
Published: April 2012

Summary
A common problem in many waterflooded oil reservoirs is early water breakthrough with high water cut through highly conductive thief zones. Thermally active polymer (TAP), which is an expandable submicron particulate of low viscosity, has been successfully used as an in-depth conformance to improve sweep efficiency of waterfloods.
This paper describes the workflow to evaluate technical feasibility of this conformance technology for proper pilot-project designs supported with detailed simulation studies. Two simulation approaches have been developed to model properties of this polymer and its interaction with reservoir rock. Both methods include temperature-triggered viscosification and adsorption/retention effects. Temperature profile in the reservoir is modeled by energy balance to accurately place this polymer at the optimum location in the thief zone. The first method considers a single chemical component in the water phase. The second method is based on chemical reactions of multiple chemical components. Both simulation approaches are compared and discussed.
Results show that temperature-triggered polymers can increase oil recovery by viscosification and chemical adsorption/retention, which reduces thief-zone permeability and diverts flow into unswept zones. Sensitivity analyses suggest that ultimate oil recovery and conformance control depend on the thief-zone temperature, vertical-to the horizontal-permeability ratio (Kv/Kh), thief-zone vertical location, injection concentration and slug size, oil viscosity, and chemical adsorption and its reversibility, among other factors. For high-flow-capacity thief zones and mobility ratios higher than 10, oil recoveries can be improved by increasing chemical concentration or slug size of treatments, or both. Reservoirs with low Kv/Kh (&lt; 0.1) and high permeability contrast generally shows faster incremental recoveries than reservoirs with high Kv/Kh and strong water segregation.
The presented workflow is currently used to perform in-depth conformance treatment designs in onshore and offshore fields and can be used as a reference tool to evaluate benefits of the TAP in waterflooded oil reservoirs.
Mechanics of Heavy-Oil and Bitumen Recovery by Hot Solvent Injection
Authors: Pathak V.. , Babadagli T.. , Edmunds N.R.. R. 
Published: April 2012

Summary
In earlier work (Pathak et al. 2010, 2011), we presented the initial results for heavy-oil and bitumen recovery using heated solvent vapors. The heavy-oil- and bitumen-saturated sandpack samples of different heights were exposed to heated vapors of butane or propane at a constant temperature and pressure for an extended duration of time. The produced oil was analyzed for recovery, asphaltene content, viscosity, composition, and refractive index. Recovery was found to be very sensitive to temperature and pressure.
The current work was undertaken to better understand the physics of the process and to explain the observations of the earlier experiments using additional experiments on tighter samples of different sizes, numerical simulation, and visualization experiments. The effects of temperature and pressure on the recovery were studied using a commercial reservoir simulator. Propane and butane were used as solvents. Asphaltene precipitation was also modeled. A qualitative history match with the experiments on different porous-media types was achieved by mainly considering the permeability reduction caused by asphaltene precipitation; pore plugging; the extent of interaction between the solvent and oil phases; and parameters such as model height, vertical permeability, and gravity. The effect of asphaltene deposition on models of varying permeabilities was also studied.
To investigate the phenomenon further, visualization experiments were performed. 2D Hele-Shaw models of different dimensions were constructed by joining two Plexiglass sheets from three sides, or in some experiments, from all sides. The models were saturated with heavy oil and left open on one side (or all sides) and were exposed to different types of solvents. The setup was monitored continuously to observe fluid fronts and asphaltene precipitation.
By use of this analysis, the mechanics of the process was clarified from the effect of solvent type on the recovery process. The optimum operating temperature for the hot-solvent process and the dominant mechanisms were identified. The dynamics of the asphaltene deposition and its effect on oil recovery were clarified through visual and numerical models.
Experimental Evaluation of Well Perforation Methods as Applied to Hard Limestone
Authors: Lewelling Henry 
Published: April 2012

Abstract
An experimental investigation of the relative effectiveness of standard bullets and "shaped charges" in perforating dense, hard formations is reported. A method is described which simulates the conditions under which a shot is normally fired. Results are evaluated on the basis of depth of penetration, extent of fracturing, extent and nature of formation damage, and other physical characteristics.

Introduction
A study was made of the relative merits of bullets and "shaped charges" as applied to well completions in hard dense formations such as those encountered in the Permian Basin. The planning of the laboratory program stipulated that core samples should he prepared and mounted in such a way that perforation shots of either kind could be fired into them, keeping the factors pertinent to good shooting practice similar to what they would be in a well.
The shooting was done in a buried tank, with the sample and shooting equipment covered with water. The depth of water was calculated to be sufficient to simulate the inertial effects of well fluids for the duration of an explosion (a few micro-seconds).
Flow measurements were attempted on the specimens after perforation. Due to the lack of uniformity of the limestone, shale breaks, etc., these measurements proved to be of little value to the study. The mounting materials were removed, so that the character of the penetration, fracturing, etc., could be observed.

Method
Laboratory samples were selected from the hard, dolomitic sand cores from Block 31 Field. Core pieces having a 3% in. diameter and a useful length of 10 to 12 in. were used. Selection was aimed at those pieces having a minimum of shale streaks and other irregularities. The ends were cut off square with the diamond saw. Prior to being mounted, the cores were soaked in water to prevent them from absorbing water out of the wet concrete, thus weakening it.
Correlation of Radioactive Logs of the Lansing and Kansas City Groups in Central Kansas
Authors: Morgan John V. 
Published: April 2012

Abstract
Although the Lansing-Kansas City groups constitute one of the more important producing horizons of Central Kansas, exploitation has been hindered by inability to consistently identify and correlate the various productive intervals. A study of gamma ray-neutron logs and core data indicates that definite zones exist which are related to production and which may be generally correlated over an appreciable portion of Central Kansas. A suggested system of zoning and nomenclature is developed and illustrated, along with examples of its specific application in overall evaluation and in development of zonal production characteristics. General adoption of the suggested system should aid appreciably in the future development of commercial Lansing-Kansas City production in Central Kansas. It is probable that similar systems might be developed for other regions where production is obtained from various uncorrelated and unnamed zones in thick pay intervals.
Generalized Geology of Central Kansas
The most important large subsurface feature in Central Kansas regarding oil production is the Barton Arch, which is part of the Central Kansas uplift. The Barton Arch is a buried ridge of Pre-Cambrian granite running northwest-southeast, near which the majority of Central Kansas oil fields have been found. To the northeast of this arch, the granite dips sharply into the Salina Basin and similar basin areas to the west and south are termed the Hugoton Embayment and Anadarko Basin, respectively. This report deals primarily with the region of the Central Kansas Uplift and its southwestern flank. Fig. 1 indicates the general location of subsurface structural features along with the oil and gas fields of Central Kansas.
Above basal granite lies the Cambro-Ordovician Arbuckle Dolomite which is the principal oil producing zone in Central Kansas. This formation, as well as those higher in the section, reflects the general underlying granite structure; however, the Arbuckle top is an erosional surface and most oil producing structures are probably topographic hills.