bluuebunny/crossref_metadata_2025_split huggingface dataset:
Results of Thermal Horizontal Completions with Sand Control in Lake Maracaibo, Venezuela: Case Histories of Horizontal Gravel Packs in Bachaquero-01 Reservoir
Authors: Pizzarelli S. G. , Gonzalez O. E. , Justiniano P. , Olivares S. A. , Potma J. J. 
Published: December 2007

Abstract
The heavy-oil reservoir Bachaquero-01, in the Lagunillas district of Venezuela's Lake Maracaibo, has been productive since 1934. Because the oil gravity is only 12° API, steam has been injected since 1971 to increase production. To further optimize production, stand-alone horizontal wells have been drilled since 1996. However, in only 4 months after steam was injected into the horizontal wells, a very fast decline of up to 50% of initial production was observed in these nongravel- packed wells.
In a drilling-and-completion campaign from October 2000 to January 2001, 18 horizontal wells were successfully drilled and gravel-packed. In this paper we describe the gravel-pack techniques applied to minimize the rapidly declining rate of production in horizontal alternate steam-injection wells. We explain the method used for screen and gravel-size selection and summarize the completion operations and gravel-pack fluids that were used. We describe the modification of an existing hydraulic packer with a high-temperature seal of 600°F—a combination used for the first time worldwide. Finally, we illustrate the successful drilling-and-completion campaign with case histories and production performance.
The gravel-packed wells had an average increase of 15% productivity after 1 year with no sand production. The gravel- pack operations were executed at a pump rate of 2 to 3 bbl/min with a sand concentration of 0.5 to 0.7 pounds of proppant per gallon added (ppa), observing continuous fluid returns of 50% to 80%. The packers were successfully field tested after a period of three weeks of steam injection.
Implementation of Advanced Cementing Techniques to Improve Long Term Zonal Isolation in Steam Assisted Gravity Drainage Wells
Authors: Stiles David , Hollies Doug 
Published: December 2007

Abstract
Steam Assisted Gravity Drainage (SAGD) development of the Athabasca oil sands has led to a unique approach to horizontal drilling combining many existing and new technologies. From a cementing perspective, preventing degradation of the cement sheath due to induced stress cracking and preventing gas migration are the two main challenges that must be addressed in order to achieve the objective of long-term zonal isolation across the length of the wellbore.
One of the main functions of cement is to prevent fluid communication between formations or to surface throughout the life of the well, including after abandonment. Even when cementing operations have provided a good initial hydraulic seal, changes in downhole conditions can induce stresses to destroy the integrity of the cement sheath resulting in a loss of zonal isolation. Changes in downhole stress conditions that occur during the life of a SAGD well are particularly extreme. Stresses in the cement sheath induced by extreme temperature cycling can result in severe mechanical damage and ultimate failure of the cement sheath, potentially leading to leakage of steam from the reservoir. Along with the requirement of maintaining cement sheath integrity, special cement design and placement considerations must be taken to prevent annular gas influx and migration. Annular gas migration prior to the setting of the cement can lead to channels that would not only provide a pathway for gas but also a potential conduit for steam to escape into shallower zones or to surface.
A new approach to cement design was undertaken to fulfill the requirements of cementing PanCanadian's (now EnCana Corp.) SAGD wells in Christina Lake. A cement system with improved flexibility to resist stress cracking was designed and implemented. This system is engineered to have a low Young's Modulus while maintaining high compressive and tensile strengths as compared to conventional cement systems. The permeability of the set cement is very low, yielding a material that is highly resistant to attack by corrosive fluids. Finally, the system is designed to be gas tight to prevent gas migration. This paper presents data on the new cementing techniques and technologies used as well as case history results on the six wells cemented at Christina Lake.
Feasibility of Fluid-Jet Based Drilling Methods for Drilling through Unstable Formations
Authors: Gupta A. , Summers D. A. , Chacko S. V. 
Published: December 2007

Abstract
This paper presents the development of fluid-jet methods for the drilling of wells through unstable formations. The work demonstrates the technical capabilities of drilling through unstable formations including Methane hydrate and permafrost.
Abrasive fluid-jet systems are capable of drilling through rocks of all types, and with greater directional control that is not susceptible to the geologically induced deviations encountered with mechanical bits, since no mechanical contact is made with the rock while drilling. Abrasive fluid-jets drill rock through the erosion induced by very small particles which individually remove only small fragments but are in such numbers that the drilling rate is at or above that of conventional tools. The particles are powered by the velocity of the supporting fluid, generated in turn by pumps on the surface. The cutting occurs ahead of the nozzle body allowing a casing to be used which is of a larger diameter than the drilling assembly itself. Abrasive jets drill through the erosion of the rock under the specific impact point of the jet contact. They do not therefore exert significant force to the rock around the drilling point and erode the rock without inducing great disturbance to the surrounding material, thus enhancing borehole stability. Fluid-jet methods have the potential of improving drilling efficiency through unstable formations.
The Fourth Horizontal Project in the Mature Algyõ Field
Authors: Pipicz V. , Benedek L. , Palásthy Gy. , Báródi T. , Blahó J. , Joshi S. D. 
Published: December 2007

Abstract
Since 1993, about 70 horizontal wells, have been drilled in three different successful projects. These projects were implemented in the mature Algyõ field. A fourth project, consisting of more than 20 new horizontal sections, kicking off existing abandoned wells, has been developed for the thin oil rim present in two high permeability reservoirs with top gas and bottom water The main difference between the two reservoirs is that one has water injection and the other has two layers with strong natural bottom water drive.
The first experimental wells of the 4th project were drilled to minimize the coning effects and to increase the areal recovery efficiency in the initially 9 and 6 m thick oil zones (shrinked to 4 and 3 m in the recent state of exploitation).
To decision about the project implementation was based on reserve re-evaluation. The re-evaluated reserves were determined using results of the experimental wells, a 3D geological model, a full field 3D simulation and horizontal well production matches with JTI software. To define saturation, neutron logs were used to determine for the gas-oil contact and carbon-oxygen logs are used for monitoring the oil-water contact (because of the very low salinity of formation water). The target zone of the horizontal sections is +/− 0.5 m vertically and very detailed information analysis is required to plan proper trajectories.
The recent state of the project, the evaluation, methods and simulation process used for the decision- making are presented in the paper.
Alternate Fuels for Thermal Projects
Authors: Garnier O. F. , Cupcic F. 
Published: December 2007

Abstract
Heavy oil developments in the Athabasca area require large quantities of steam, and this becomes a major expense when natural gas is used in Once Through Steam Generators. This paper reports on an exploration of possible ways to reduce these costs by using alternative fuels obtained from an integrated upgrader.
Depending on the upgrader selected, associated waste streams are produced such as petcoke, asphalt or unstable vacuum residue from which little or no value can be drawn in the Athabasca area except by exploiting their heating value. Combustion of these waste streams is not technically a problem, but the cost of using an alternative fuel is strongly impacted by the specific water treatment required and the problem of sulphur oxide emissions.
Present configurations for heavy residue boilers require high-quality demineralised water, and the related water treatment represents a higher cost than for the partly softened feed water used in conventional Once Through Horizontal Steam Generators (OTHSG). Combustion of high sulphur fuels calls for an efficient desulphurisation method in order to meet the increasingly stringent statutory emission limits. Traditional methods using limestone involve injection and the problematic disposal of large quantities of solids.
This study has characterised four types of upgrading residues, namely petcoke, asphalt, unstable vacuum residue and heavy crude oil, in terms of their nature and sulphur content. It has determined for each fuel the appropriate boiler configuration, including flue gas depollution and water treatment, and compared its cost with that entailed in the common practice of producing steam with natural gas in Once Through Steam Generator (OTSG) field units. Regenerable SO2 scrubbing techniques coupled with Claus units have been investigated, as possible means of producing pure liquid or solid sulphur. By converting upgrading residues into syngas by partial oxidation, cleaning up the syngas by removing its sulphur and sending the clean syngas to OTHSG unit, both the water treatment requirements and the SO2 emission limits can be met. The cost of such a solution has been compared to that of direct combustion of residues in a boiler.
Heavy Acidic Oil Transportation By Emulsion In Water
Authors: Verzaro F. , Bourrel M. , Garnier O. , Zhou H. G. , Argillier J-F. 
Published: December 2007

Abstract
This paper sets out to demonstrate, at lab scale, the feasibility of the two main phases of the process, namely the emulsification of a heavy Venezuelan acidic crude oil (ZUATA), and the subsequent breaking of the oil-in-water emulsion.
The heavy ZUATA crude can be emulsified directly by making use of the surfactants naturally present in this rich acid oil. These potential surfactants, mainly represented by naphthenic acids, become effective emulsifiers when salified into naphthenate anions by the addition of bases (soda, ammonia).
Stable oil-in-water emulsions, typically with 60 to 65% oil, are obtained by using these two bases. There are a number of advantages to be gained in using ammonia to form the oil-in- water emulsions as opposed to other bases (soda for example) for emulsion breaking and phase separation.
The paper demonstrates that it suffices to heat the emulsion to break it. It describes the conditions required for ammonia removal and recovery, and the resulting emulsion breaking.
An industrial process for achieving the separation is then proposed.
Innovative Design Allows Construction Of Level 3 Or Level 4 Junction Using The Same Platform
Authors: Desai Praful , McGarian Bruce 
Published: December 2007

Abstract
The simple and most economical multilateral option in the production of heavy oil with optimum solids control is to employ either level 3 or level 4 junctions to access and drain oil bearing sand bodies.
This paper presents an innovative junction design which when fully deployed, can be left as a level 3 construction, or it can be turned in to level 4 by conventionally cementing the junction. In practice the isolation provided with the level 3 construction far exceeds the capabilities of conventional alternatives, and when cemented as a level 4, provides a junction with stability beyond that afforded by conventional methods. In either scenario, access to the main bore below the junction and to the lateral bore is maintained.
Once the junction is in place, conventional completion equipment can be run after drilling the lateral to facilitate the production.
In addition, this innovative junction offers other advantages. Among those are, (1) Milling or washover of excess liner is not required when constructing a level 4 junction because there is no excess liner left in the main bore during the junction construction. (2) The lateral liner can be deployed simultaneously with the junction for both level 3 and level 4 junctions. (3) The platform allows full re-entry capability into main and lateral bores in a single or stacked junction configuration.
The paper will also discuss in detail, recent field installations and developments of this innovative design in level 4 complexity in 9-5/8" 40 lb/ft casing.
Major system components and their functions are described, as well as running procedures and lessons learned.
Chemical Removal of Organic Foulants from Produced Water Recycled as Steam
Authors: Hart Paul R. 
Published: December 2007

Abstract
A limitation on the use of produced water as steam to assist oil recovery by gravity drainage (SAGD) from oilsands is the presence in the water of boiler foulants. Ordinary water clarification treatments were found to leave behind certain classes of organics that shorten boiler cycle times. Using molecular probes to compare produced water from SAGD processes having different rates of boiler fouling, an unstable class of organic colloid was identified, and a new chemical treatment developed to remove it.
An Inexact Air Quality Model for Petroleum Pollutants Based on Techniques of Factorial Analysis and Stochastic Simulation
Authors: Zou Yun , Li Jianbing , Huang G. H. , Li Hengliang 
Published: December 2007

Abstract
In this study, an inexact air quality modeling system is developed to predict the maximum ground level concentration (MGLC) and distance to MGLC (DMGLC) of gaseous pollutants from point sources in petroleum operations. The influence of uncertain parameters is evaluated through an integration of 2k factorial analysis and stochastic simulation. The results can provide useful information for risk assessment and decision analysis.
Innovative Use of the Well Freeze Technique for Repairs on Steam Injection Wells in a Thermal Recovery Project
Authors: Zatka M. J. , Foutz T. , Finley D. 
Published: December 2007

Abstract
Although isolation of lines and wellheads using ice plugs is not new in itself, the liquid nitrogen approach developed for use on Aera Energy LLC’s ("Aera’s") Diatomite Steam Drive steam injection wells offered several creative and novel aspects. The procedure was first thoroughly shop-tested and then field-tested on two wells. Bentonite gel was used as a plugging agent due to its rheological characteristics and low thermal expansion compared to water. The gel was mixed to ensure sufficient viscosity to remain in place once spotted across the freeze interval. Cooling was applied by circulating cold nitrogen gas through copper tubing wrapped on the outside of a 13⅜" surface casing string. Contact temperatures on the surface of the external casing were closely monitored to ensure they were never lower than approximately –100°F throughout the process to minimize risk of casing embrittlement.
At 12 hours or less on each well, the time to form ice plugs to the core through a multiple string completion and two cement layers was very manageable. All seven injection strings above the wellhead on the two test wells were safely cut off, and each string fully converted to the desired new injection configuration above the casing bowl.
Thorough safety and technical planning prior to the field trials, creation of several new tools to assist with various program steps, and identification / consideration of contingencies helped in avoiding mistakes, encountering difficulties during the job and, ultimately, making the trials a thorough success.
Opportunities of Downhole Dielectric Heating in Venezuela: Three Case Studies Involving Medium, Heavy and Extra-Heavy Crude Oil Reservoirs
Authors: Ovalles Cesar , Fonseca Anyaleth , Lara Ali , Alvarado Vladimir , Urrecheaga Kerin , Ranson Aaron , Mendoza Humberto 
Published: December 2007

Abstract
The use of electromagnetic radiation, radiofrequency (RF) and microwaves (MW), for downhole dielectric heating has potential applications in enhanced/improved oil recovery processes (EOR). The Lambert’s equation was coupled to a commercial simulator in order to model reservoir dielectric heating. Using a MW heated (2.45 GHz) one-dimensional reactor, this mathematical model was validated in the presence of crude oil/sand cores. Three different conceptual reservoirs were evaluated which involved a medium crude oil (24°API), a shallow (1100 ft) Lake Maracaibo heavy oil (11°API) and a thin pay zone (20 ft) Orinoco Basin extraheavy crude (7.7°API). For all the cases evaluated, numerical simulation results showed an important acceleration in the oil production due to RF and MW heating which was attributed to reduction of crude viscosity coupled with favorable relative water-to-oil permeabilities. For example, in the shallow heavy oil case, RF heating led to an increase of 86% of the cumulative oil production in comparison with the cold production case, using 140 MHz at 50 kW over a ten-year period. Furthermore, calculated energy gains (measured as the ratio between the energy extracted as crude oil equivalent to energy added to the reservoir as electricity) were in the 8 to 20 range, indicating that the process is favorable from the thermodynamic point of view. These conceptual numerical simulation results indicate the high potential of dielectric heating technology for medium, heavy and extra-heavy EOR with possible field applications.
Long-Term Performance of Multilaterals in Commingled Reservoirs
Authors: Yildiz Turhan 
Published: December 2007

Abstract
In this study, a comprehensive transient model was developed for multilateral wells producing from multiple formations separated by impervious streaks. Model is flexible and is capable of simulating the flow with any number of layers, unequal initial layer pressure, non-uniform petrophysical properties for each layer, and unequal layer size. Additionally, each lateral can have nonuniform formation damage and may be selectively completed.
We investigated the long-term rate decline and cumulative recovery response of the multilateral wells connecting multiple isolated formations. Total flow rate, cumulative production, and fractional rate for each branch, are all compared for several completion scenarios and layer properties. Crossflow between the layers through the wellbore is also evaluated.
First Horizontal Well Opens New Gas Opportunities in the Sierra Chata Field, Neuquén Basin-Argentina
Authors: Sanz C. A. , Nilson G. J. , Acree J. F. , del Pino M. , Anaya L. 
Published: December 2007

Abstract
The first horizontal re-entry gas well was successfully drilled and put on line in the Sierra Chata field in the Neuquén basin in Argentina. This article compares the model forecast with the results obtained. The objectives were: (1) to add gas reserves and (2) to incorporate horizontal technology that will allow access thin or low permeability sands, in remote areas that would be economically marginal with vertical wells.
Recent interpretation of 3-D seismic and geologic data indicated that the "D" Sands were better developed to the northwest of the vertical well SCh-17. In order to access gas reserves postulated to exist there, it was planned to drill a horizontal re-entry well utilizing the existing vertical well, SCh-17 as a re-entry conduit. From the well SCh-17 a re-entry was made at 244 m from the deviation point (KOP) in 1600 m MD, drilling slightly up-dip to 2975 m MD, using with a downhole motor and a MWD logging system.
Shale-silt lithologies within the sand members affect the vertical transmissibility (TZ) between the "D" Sand members. Sensitivity runs were made using a reservoir simulator built to test the effect of such variables on the horizontal well productivity. For the most probable case, an initial flowrate of 17.7 MMscfd (502 Mm3/d) was predicted. A final cumulative production of 7.3 BSCF (206.7 MMm3) of gas was predicted by the numerical simulation model.
Three years of production history confirmed the forecast and assumptions made in the well proposal and also encourage new horizontal prospects.
Fault Interpretation Strategy for 3D model Simulation
Authors: Mendoza P. , Floricich M. 
Published: December 2007

Abstract
Advances in computing technology have allowed the development of sophisticated 3D cellular modeling and visualization software, which has found a variety of applications in the oil industry. This technology includes spatial attribute modeling and the visualization of hydrocarbon reservoirs to improve the understanding of the geological structure including internal features and the distribution of formation properties.
This paper discusses experiences gained in building a geological model for the LL-03 reservoir (in this reservoir there is a horizontal well drilling strategy) and the subsequent manipulation and transfering of this data into a 3D reservoir simulator for initialization purposes.
The paper covers the modeling of fault planes in complex reservoirs, the handling of both vertical and sloping fault surface and the distribution of petrophysical properties (porosity, permeability and water saturation) of the geological model to be used in the reservoir simulation.
The technique presented here differs considerably from the traditional method for fault interpretation. This new method consists in interpreting the plane that describes the fault in the space, using several techniques that allow defining the structural framework. Advantages for both, geocientists and reservoir engineers in displaying and reviewing the 3D image of the fault planes and the reservoir at an early stage in the project are discussed.
The paper concludes with suggestion for developments of the workflow to create the most realistic fault plane according to the structural framework to further enhance the effectiveness of the present 3D modeling method.
Downhole Conversion of Lloydminster Heavy Oil Using THAI-CAPRI Process
Authors: Xia T. X. , Greaves M. , Werfilli W. S. , Rathbone R. R. 
Published: December 2007

Abstract
THAI - ‘Toe-to-Heel Air Injection’ is a radically new process for the recovery and in-situ upgrading of heavy/medium crude oil and bitumen. It is an integrated-horizontal wells process, which creates its own natural sealing mechanism (in the horizontal producer well), enabling stable combustion front propagation along the horizontal producer well to be achieved. CAPRI is an extension to the basic THAI (thermal) process, which involves the emplacement (‘gravel-packing’) of a standard refinery HDS catalyst, around the horizontal producer well.
A series 3-D combustion cell experiments were performed to physically simulate the THAI-CAPRI process, using Lloydminster heavy crude oil (11.9°API). In separate THAI and CAPRI experiments, high temperature combustion was sustained (500-550°C), achieving stable combustion front propagation. Very high oil recovery was achieved, exceeding 79 % OOIP for THAI and CAPRI. The first-stage of downhole conversion, or in-situ upgrading, is accomplished by thermal cracking (THAI), and thermally/catalytically, in the second stage (CAPRI). Thermal upgrading of the produced oil by THAI averaged 18.3 °API - an incremental conversion gain of 6.4 API points, with a maximum of 22 °API. Higher upgrading was achieved by CAPRI using a regenerated CoMo HDS catalyst. The produced oil averaged 23°API, essentially a light oil product. The oil viscosity produced by THAI or CAPRI was as low as 20 to 30 mPas.