bluuebunny/crossref_metadata_2025_split huggingface dataset:
SAGD Application In Gas Cap and Top Water Oil Reservoirs
Authors: Nasr T.N. , Law D.H.S. , Beaulieu G. , Golbeck H. , Korpany G. , Good W.K. 
Published: March 2010

Abstract
The paper presents experimental results on the impact of top water and gas caps on SAGD performance. The effect of the top thief zone on oil drainage rates and potential oil and steam loss into the top zone were measured. The study involved the use of a large scale high-pressure/high temperature experimental facility for injecting steam into an oil sand pack and measuring oil drainage rates and development of temperature ahead of the steam chamber. Numerical modelling was conducted to predict field scale performance using the CMG's STARS simulator.
An elemental experimental approach was used in the study to simulate a generic reservoir in the Athabasca region with a pay zone thickness of 50 m and an overlying thief zone thickness of 8 m. In this approach, a reservoir element was selected close to the oil/top thief zone interface. The element was located ahead of an advancing steam front. In order to set the initial conditions of the laboratory element to be similar to those in the field, field scale numerical simulation was conducted to determine the temperature distribution in the element. The field scale temperature profile was established in the laboratory elemental model to represent the element's initial temperature before the start of steam injection during the experiments.
The paper discusses the results from the study and highlights the potential implications of the top thief zone on SAGD applications. In addition, differences between gas cap and top water thief zones on impacting the thermal and recovery efficiency of the SAGD process are demonstrated.

Introduction
There is a major concern by oil producers that the gas production from the gas cap overlying the oil sand deposit has a significant detrimental effect on oil recovery. A case in point is the Surmont oil sands lease in the Athabasca deposit in Alberta, Canada, where ConocoPhillips operates a Steam Assisted Gravity Drainage (SAGD) pilot, and plans to follow quickly by commercial development. The lease has a top gas zone and a mobile water sand zone overlying the oil sand pay zone. An observation well indicates that the gas cap pressure at the pilot site has fallen from 1,327 kPa to 858 kPa over three years due to production of the gas. It is estimated that the pressure may fall to less than 300 kPa before the gas wells are abandoned. Based on the geology and pressure measurements, there is communication between the gas cap and the oil sands. This indicates that the gas cap may be a thief zone at the pilot site. It is also believed that the mobile top water zone may extend the area of influence of the pressuredepleted gas cap.
As part of the ADOE/EUB Task Force's study of this problem, numerical studies on SAGD processes in reservoirs with top water/gas cap zones were conducted by ADOE(1, 2) as well as the oil and gas producers.
Field-Scale Numerical Simulation of SAGD Process With Top-Water Thief Zone
Authors: Law D.H.S. , Nasr T.N. , Good W.K. 
Published: March 2010

Abstract
There is a major concern that the existence of thief zones, such as top water and/or a gas cap overlying the oil sand deposit, has a detrimental effect on the oil recovery in the application of the steam-assisted gravity drainage (SAGD) process. The objective of this numerical study is to investigate SAGD performance in the Athabasca oil sands in the presence of a top water zone.
The reservoir model, STARS, developed by the Computer Modelling Group (CMG) Ltd., has been previously validated based on a 3D SAGD laboratory experiment with top water that was conducted at the Alberta Research Council (ARC). It is believed that the numerical simulation captured the major mechanism of oil movement from the pay zone into the top water zone, as was observed in the experiment.
In the field-scale simulation, SAGD performance in the presence of confined and non-confined top water zones was investigated. The operating strategies under the conditions of non-depleted top water/non-depleted pay zones and depleted top water/non-depleted pay zones were considered. Numerical findings indicated that:there is a detrimental effect of a top water zone on SAGD performance;plugging of a top water zone with oil was not observed in this study for a top water thickness of 8 m; and,operating conditions that lead to a higher pressure difference between the steam chamber and the top water, either by depletion of the top water zone pressure or a higher steam injection pressure, results in a more detrimental effect on the SAGD performance.

Introduction
There is a major concern by Alberta oil producers that the production of natural gas in association with oil sands would lower reservoir pressure, reduce oil recovery, and may prohibit economic oil recovery. The Alberta Department of Energy (ADOE) and Alberta Energy and Utilities Board (AEUB) initiated a series of field-scale numerical modelling studies(1, 2) to assess the potential applicability of the steam-assisted gravity drainage (SAGD) oil recovery process under a variety of reservoir conditions such as reservoir thickness, reservoir depth, initial pressure, oil saturation, and the presence of top water zones and gas caps. It was found that top water zones and gas caps are thief zones to the SAGD process. These thief zones have a detrimental effect on SAGD recovery performance, especially when the pressure in the thief zones is reduced below optimum SAGD operating pressures due to natural gas production. Movement of oil into the top water zones and gas caps is simulated to occur. The volume of this oil seems to be generally proportional to the amount of outflow from the pattern due to the thickness of the top water zones/gas caps and the pressure difference between the steam chamber and the top thief zones. SAGD process costs depend on the amount of steam that flows into the top water zones and gas caps, from which no oil is produced.
Flue Gas Injection Into a Mature SAGD Steam Chamber at the Dover Project (Formerly UTF)
Authors: Yee C.T. , Stroich A. 
Published: March 2010

Abstract
The Dover Project (formerly the Underground Test Facility) is the world's first field pilot of the Steam Assisted Gravity Drainage (SAGD) process using dual horizontal well pairs to recover bitumen. There have been four phases of SAGD piloting at the Dover site thus far. The Phase B pilot, which consists of three 500 m long horizontal well pairs spaced 70 m laterally apart, has been in continuous operation since early 1993. Phase B reached the peak production rate of 300 m3/d or 100 m3/d per well pair on average in the middle of 1994. After sustaining the peak rate for about two years, the production has been in decline with a steady increase in steam-oil ratio. Research carried out in the past few years suggested that the addition of a suitable amount of non-condensable gases (NCG) would be an effective method to wind-down the steam chamber. It provides an economic means to continue bitumen production by utilizing the large amount of heat stored in the SAGD chamber. Beginning in April 1998, a small amount of natural gas was added continuously to the steam injection. The concentration of NCG has increased steadily in the past 3.5 years. The resulting performance has been better than initially expected. Based on the success of this NCG-steam wind-down strategy, a four-month flue gas injection test was conducted in 2001 to investigate the possibility of using the more cost-effective flue gas, rather than natural gas as an injectant.
This paper summarizes the rationale for selecting the NCG-steam wind-down strategy, the field implementation of the flue gas injection test, and the resulting pilot performance. The successful implementation of this technology will have a profound impact on the overall process economics.

Introduction
The Dover Project is an in situ bitumen recovery facility on the Oil Sands Lease Number 328 located 70 km northwest of the City of Fort McMurray. It was initiated by Alberta Oil Sands Technology and Research Authority (AOSTRA) in 1984 and was ater joined by industry participants to pilot the SAGD processsing dual horizontal wells. The Dover Project Area is located in eight sections of land at the extreme eastern edge of the lease, as shown in Figure 1. To the immediate east of Dover is Petro-Canada's MacKay River Project, which is expected to produce 30,000 BOPD using the SAGD process in 2003.
Several papers(1–3) have been published to describe, in detail, the Dover Project from the beginning until mid-1997. The following is a brief summary.
FIGURE 1: Dover project area. Available in Full Paper.
The first phase of testing, Phase A, involved the drilling of horizontal wells from a limestone tunnel network located about 20 m below the oil sand formation. These well pairs had a horizontal length of about 60 m and were spaced 25 m apart, as shown in Figure 2. They were operated from 1987 to 1991. Encouraged by the results from Phase A, the Project proceeded to the secondphase of piloting in late 1991.
Issues With Reservoir Geomechanical Simulations of the SAGD Process
Authors: Li P. , Chalaturnyk R.J. , Polikar M. 
Published: March 2010

Abstract
In the SAGD process, steam injection may result in pore pressure changes around the steam chamber in the reservoir. The magnitude of the pore pressure change depends on the steam injection pressure and the relative position of the steam chamber within the reservoir. Injected steam also increases the temperature within and adjacent to the steam chamber and thus introduces thermal expansion effects. The complex interaction of pore pressure and temperature throughout the reservoir result in varying degrees of reservoir geomechanical interactions that must be considered when contemplating reservoir geomechanical simulations of the SAGD process.
The primary geomechanical influence on SAGD recovery is associated with the volume change of the sand matrix in response to effective stress changes induced by steam injection pressures and temperatures.
Reservoir parameters and processes, such as compressibility, porosity (pore volume), absolute permeability, relative permeability, saturations, capillary pressure, enthalpy transmissibility, gas evolution, and thermal expansion effects, are all affected by bulk volume changes. In this paper, variations of these parameters due to geomechanical effect are analyzed and discussed based on related test results, calculation, and simulation. Their impacts on reservoir geomechanical simulations of the SAGD process are discussed.

Introduction
Reasonable prediction of SAGD performance by numerical simulation is an integral component in the design and management of a SAGD project. Conventional reservoir numerical simulation emphasizes multiphase flow in the porous media but generally does not take the interactions between fluid and solid into account. It applies elastic rock compressibility to characterize the coupling mechanism of multiphase flow and rock skeleton. The assumption of this treatment is that the boundary loads and temperature are constant, Δp = Δ σ'(1, 2). All analytical flow equations in petroleum engineering are based on this assumption. It is clear that the recovery process of conventional oil from sandstones and most carbonate rocks can roughly satisfy this assumption. For the SAGD process, however, volumetric deformations within the reservoir due to pore pressure and temperature changes result in variations of both in situ stress and strain. These stress and strain variations are functions of the in situ boundary conditions. Due to different directional deformation in response to in situ heating, the total stresses in vertical and horizontal directions may also vary. Moreover, the SAGD process is mainly applied in friable or uncemented (unconsolidated) oil sands that geomechanically behave differently to their cemented counterparts. Under these conditions, the assumption used in conventional numerical simulation is no longer effective because the total stress changes within the reservoir.
Multiphase Equilibria Calculation by Direct Minimization of Gibbs Free Energy Using the Tunnelling Global Optimization Method
Authors: Nichita D.V. , Gomez S. , Luna-Ortiz E. 
Published: March 2010

Abstract
In this paper, we advocate the use of the Tunnelling global optimization method for phase stability analysis and for multiphase equilibria calculations. The method had been successfully used for solving a variety of phase-equilibrium problems. The Tunnelling method has two steps. First, a minimum (which may not be the putative global minimum) of the objective function is found by a local bounded minimization algorithm. In a second step, the method checks for global optimality. If the minimum found in the first step is only a local minimum, a feasible initial estimate for a new minimization is generated in another valley of the objective function.
Cubic equations of state are used, but any thermodynamic model for the Gibbs free energy can be used (the method being model-independent). The proposed method has proven to be an efficient and reliable tool for multiphase equilibrium calculation.

Introduction
The methods for multiphase equilibria calculation based on the equality of chemical potentials cannot guarantee the convergence to the correct solution since the problem is non-convex (i.e., several local minima exist), and such methods can find only one minimum for a given initial guess. Moreover, the global optimization methods currently available are generally very time consuming.
A global optimization method(1, 2), called Tunnelling, able to escape from local minima and saddle points, is used in this work for the direct minimization of the Gibbs free energy and of the tangent plane distance function (TPD). The Tunnelling method has two phases. In phase one, a local bounded optimization method is used to minimize the objective function. In phase two (tunnelization), either global optimality is ascertained or a feasible initial estimate for a new minimization is generated.
The Tunnelling method has shown its ability in efficiently solving difficult non-convex, highly non-linear problems. Different kinds of phase equilibrium problems were solved using Tunnelling(3–6).
The problems addressed here are vapour-liquid and liquid-liquid two-phase equilibria, three-phase vapour-liquid-liquid equilibria, and three-phase vapour-liquid-solid equilibria for a variety of representative systems.
We use in this work a general form of cubic equation of state (EOS), incorporating the Soave-Redlich-Kwong (SRK) and Peng- Robinson (PR) EOS.

Multiphase Equilibrium Equations
Phase Splitting
According to the second law of thermodynamics, at the equilibrium state, a system of nc components of composition z = (z1, z2,...,znc)T has the lowest possible Gibbs free energy from all possible states. The dimensionless Gibbs free energy is expressed as:
Design and Analysis of a Conveyor Lift Pump
Authors: Garg D. , Bhagavatula R. , Lea J.F. , Cox J.C. 
Published: March 2010

Abstract
The Conveyer Lift Pump uses viscous drag to lift liquids. The pump utilizes a flexible continuous rope or conveyer, affixed about a sheave at the top and bottom of the well moving upward inside the production tubing, viscously dragging or lifting the fluid from the well. Presented here are mathematical derivations for the flow rate, the quantity of fluid to be lifted, the required drag force at the rope surface, the power input required by the system, and efficiency of this lift system. Concentric and eccentric solutions are presented.

Introduction and Discussion
Presented here is an analysis of an artificial lift concept, which is to "rope-lift" liquids out of the wellbore, based on viscous drag between the moving rope and a liquid column in the annular space of the inner tubing wall and the rope (Figure 1). This differs from other methods of lift with details in References (1) and (2), and other methods summarized by Brown(3).
Possible applications include lifting of oil/water from relatively shallow wells, the removal of liquids from gas wells to eliminate liquid loading(2), and the possible application of the concept to the lifting of viscous oil.
The foundation of the process is based upon mathematical models with the rope being centred in the tubing and being offcentre to varying degrees. For further details, see Reference (1) [Lea(2)] with a model of a downhole pump requiring similar analysis, and Crafton(4).
The tubing on the upper end delivers the fluid that has been viscously dragged along with the rope, providing the rope speed and rope and tubing diameters and the fluid viscosity are selected to yield positive production. A rope housing supports the rope during its downward travel to prevent wear from rubbing on the casing. The fluid at the surface may have to undergo a slight "scraping" effect to prevent produced fluid from being carried back downhole.
It appears that this could be used for sandy production as no sliding metal surfaces are employed, such as those found in a downhole beam pump. Also, it may be useful for high viscosity production, as the basic concept depends on fluid viscosity for lift to occur. If treating fluids need to be pumped downhole, those fluids can be conveyed to the sandface via the return protective tubing. Another application might be to pump relatively small amounts of liquid from a producing gas well to help eliminate liquid-loading. Full-scale field experience is in short supply. One weakness appears to be depth. Some of the illustrations below indicate the force needed at the surface of the lifting rope is calculated to be excessive as deeper wells are considered. Use of the models presented here should help the user evaluate the potential of this lift concept for various production scenarios.

Models and Sample Result
Models for the rope-lift pump were developed, including the rope being concentric in the tubing and also at various degrees of eccentricity.
What is Stewardship?
Authors: Maynard Brian 
Published: March 2010

Abstract
When the Canadian Association of Petroleum Producers (CAPP) launched its Stewardship initiative in 1999, it was the first of its kind in the world-a stated commitment by CAPP members to responsible and balanced resource development and continuous improvement in environmental, health, safety, and social performance.
In the six years since then, CAPP has worked with our members to develop the initiative and better address issues of importance to our stakeholders. Today, the core Stewardship values are engrained in CAPP's 150 member companies, and the data we collect confi rms we are well along the path of continuous improvement. We're proud of our accomplishments and we've set ambitious goals for the future.
However, a lot of people-even those in the oil and gas industry- have never heard of CAPP or its Stewardship initiative. It's not surprising. While our members apply the principles of Stewardship to their own business models and operating environments, it is not something they talk about.
Here is an example:
In January, CAPP hosted its fi rst Stewardship-related event for 2005. Natural Resources Canada Minister John Efford came to Calgary to announce that four CAPP members-Anadarko Canada Corporation, Apache Canada Ltd., Penn West Petroleum Ltd., and Suncor Energy Inc.-qualifi ed for a federal program to encourage CO2 capture and underground storage.
Greenhouse gas emissions, including CO2, have been one of the key benchmarks for Stewardship since 1999, but nowhere in the national news coverage generated by the announcement did the word "tewardship" appear, nor did anyone make the connection to Stewardship.
Stewardship isn't a label that gets slapped on a product; it's an ethic that integrates economic, environmental, and social considerations through all aspects of each company's operations. That is the real essence of the initiative. However, our industry earns its license to operate through our decisions and actions and their impacts, so it is more important than ever that CAPP work to improve Canadians' knowledge, awareness, and trust of the upstream oil and gas industry.
Canada is a major contributor to global oil and gas supplies and will be for decades to come. We are the world's third largest producer of natural gas and ninth largest producer of crude oil. Daily production in Canada is greater than half the members of OPEC and, thanks to Alberta's oil sands, Canada's oil reserves are second in the world only to Saudi Arabia.
The economic impact of oil and gas activity is evident. About one-quarter of the world's drilling rigs operate in Canada and CAPP members drill more than 20,000 new wells a year. The record level of drilling activity has brought the industry into contact with an increasing number of stakeholders and communities.
In today's fast-paced, information-based world, our stakeholders have access to a variety of information sources-some accurate and some not-and they are more engaged than ever.
Coalbed Methane Development: Practices and Progress in Canada
Authors: Gatens M. 
Published: March 2010

Abstract
As conventional gas supplies decline, unconventional sources of gas, like coalbed methane (CBM), will become increasingly important in Canada. Canada has over 700 Tcf of CBM gas resource in place, comparable to the U.S. resource. Canada now has the world's largest "dry" coal play and it is estimated (as shown below) that CBM will grow to 2 - 3 Bcf/d in production over the next 10 – 20 years and lead to recovery of up to 75 Tcf of gas. Since 2000, increased drilling activity has led to over 3,000 CBM wells and 150 MMcf/d of CBM production in Canada today, with both estimated to grow substantially in 2005 and beyond. CBM will become an increasingly important part of Canada's gas supply.

Introduction
Coalbed methane (CBM) is simply the natural gas that is generated by coal seams during the coalification process. It is "sweet gas" (not sour), is largely comprised of methane (&gt;90%), and is similar to the natural gas that is burned in homes. In Alberta, the Department of Energy (DOE) refers to CBM as natural gas from coal, or NGC, to associate it with existing regulations which govern the production of natural gas. In British Columbia (BC), it is referred to by the Ministry of Energy and Mines (MEM) as coalbed gas, or CBG. Regardless of the name used, it is the same gas.
CBM reservoirs are classified as "unconventional" and have gas storage and production mechanisms that distinguish them from conventional reservoirs. Most of the gas in coal is stored in a sorbed state within the coal matrix, physically attached to the complex internal surfaces of the coal as a function of pressure, characterized by sorption isotherms(1, 2). Coals which are suitable for CBM production are naturally fractured, with closely spaced natural fractures, or "cleats," which provide pathways for gas flow from the coal matrix. In many cases, but not all, these cleats are initially full of water, which must be produced to reduce the pressure around the coal matrix allowing the sorbed gas to desorb and become free gas which can then be produced. The gas storage and production mechanisms of coals are comprehensively covered in References (1) and (2) and elsewhere in the oil and gas literature. In Canada, commercial production of CBM has only recently begun. The objective of this paper is to provide a summary of the major coal groups being targeted for development in Canada and an update on the recent evaluation and development. Predictions of future performance will also be presented.

CBM History in the U.S.
Commercial development of CBM began in the U.S. in the 1980s. Initial efforts to remove the gas from coals were funded by the U.S. Bureau of Mines primarily to improve mine safety. As natural gas value increased, the research began to focus on capturing the CBM for commercial use, and hundreds of millions of dollars were dedicated to research and development projects by the U.S. DOE, the Gas Research Institute (GRI), and the industry(3–7).