bluuebunny/crossref_metadata_2025_split huggingface dataset:
Gas Exploration And Development Strategies In the Western Canada Sedimentary Basin
Authors: Flint D.W. , Dixon R.K. 
Published: March 2010

Abstract
The Western Canadian Sedimentary Basin (WCSB) is a major source of natural gas supply for the North American market, with year 2000 basin productivity at more than 450 e6m3/d (16 Bcfd). Significant natural decline requires that in excess of 84 e6m3/d (3 Bcfd) of new supply must be added each year simply to maintain constant basin deliverability. In addition, the average rate added per well continues decreasing and the initial decline rate increasing. During the decade of the 1990s, over 700 e6m3/d (25 Bcfd) of new western Canadian gas deliverability was added, from over 42,000 new producing well events.
Based on the year of pool discovery and the year that the area was first connected to the delivery system, there are four definable strategies. Each of the four strategies (Exploration, Connection, Development, and Renewal) contributed a significant amount of gas rate additions. What role will exploration and development strategies play in future gas supply?
This paper provides an illustration of the trends in gas supply additions over the last decade, including a view of the geographic distribution, as well as other attributes. There is also a comparison of the portfolios of E&D strategies that operators employed. A brief synopsis of the methodology being followed to determine a consistent measurement of gas rate-additions is also presented.
Careful analysis of the historical results has yielded useful insights for operators as they make their choices about future activities.

Introduction
The Western Canadian Sedimentary Basin (WCSB) is a critically important source of natural gas supply for Canada and the United States. In the year 2000, the WCSB produced over 23% of the gas consumed in these nations.
Gas supply from the WCSB has increased substantially over the past decade. From a level of 225 e6m3/d (8 Bcfd) in the mid- 1980s, marketable natural gas deliveries increased to over 450 E6m3/d (16 Bcfd) in 2000. To achieve this growth in production, and compensate for the natural decline in production from existing wells, operators in Western Canada added significant new deliverability. Over 42,000 gas wells were brought onstream during the 1990s, contributing, in aggregate, 703 e6m3/d (25.1 Bcfd) in rate additions.
Supply replacement in the WCSB will be a challenge as natural decline creates a large gap in productivity each year. At 1999 production levels and decline rates, 93 e6m3/d (3.3 Bcfd) must be added yearly simply to replace decline. The production gap is growing larger each year because the total decline rate is increasing. The average decline rate has risen from 17 - 18% per year in the early 1990s to over 26% per year at the end of the decade. The increase in the decline rate was basin-wide and was observed to increase in all sources of new gas supply (by strategy employed, by geographic region, by stratigraphic group, and by reservoir depth).
In addition, the supply contribution of the average new well to fill the production gap has been decreasing.
Gravity Drainage-Lab Tests, Relative Permeability Calculation, and Field Simulation
Authors: Bonet E.J. , Cunha C. , Correa A.C.F. , Elias V.L.G. 
Published: March 2010

Abstract
In order to confirm the expected high recoveries obtained in gravity drainage field operations we performed a series of lab tests, developed an oil relative permeability calculation, and used this data to conduct a reservoir simulation for a Brazilian offshore oil field. The lab tests were conducted at ambient temperature and low pressure, and were performed in long cores (90 - 252 cm long) with dead oil and conventional production where the oil was produced at the lower end of the vertically oriented core and air entered the upper end. For one test we performed a counter-current drainage test using live oil where the production was collected at the lower end of the core and the liberated dissolved gas was removed counter-currently from the upper end. The saturation evolution inside the core was monitored by an X-Ray system. Using the same rock and fluids, centrifuge tests were performed using 3 - 4 cm long plugs to compare to the core displacement test results. When the results did not agree, an explanation for the variance using a model of bundles of capillary tubes was postulated. Verification using the principle of minimum energy was performed. A computer program was implemented to calculate the oil relative permeability using the lab data, the results of which were compared with the published literature.
The calculated relative permeability was used to simulate the behaviour of a Brazilian offshore oil field that was initially exploited with water injection, and then, due to the appearance of a secondary gas cap, subsequently subjected to gas injection into the crest of the structure.

Introduction
Numerous papers describe lab test results concerning gravity drainage(2–4, 7, 8, 10, 12, 14, 16, 19, 23, 24, 26, 27). We present the results of gravity drainage long core tests and centrifuge tests using samples with identical rock and fluid properties. In those situations where the results of the two methods did not agree, we calculated the results by considering a bundle of capillary tubes to understand the difference. The long core tests showed, in accordance with the literature, a very low residual oil saturation at the top of the core. The results of these tests were used to calculate the oil relative permeability to be used in to simulate the performance of an offshore Brazilian oil field with a 110.6 MMSTm3 OOIP has been under production for 13 years under peripheral water injection and, due to the appearance of a secondary gas cap, has been supplemented with a crestal gas injection. After a history match, we performed the production forecast for both water and combined water and gas injection.

Methodology of the Experimental Tests
Long Core Tests
After the traditional core mounting process, the sequence of the tests can be summarized in the following steps:Measurement of rock and fluid properties;Water saturation of the sample under vacuum;Displacing the water by oil and establishing the initial water saturation; and,Drainage of oil in the presence of air.
The Behaviour of Non-Condensible Gas in SAGD-A Rationalization
Authors: Butler R.M. 
Published: March 2010

Abstract
The development of the SAGD process has been facilitated by the ability to predict performance from theory. Analytical and numerical methods have given results similar to those obtained in the field and in laboratory-scaled models. It was realized before any field projects were undertaken that horizontal wells would be required and that production rates of hundreds, or even a thousand or more, barrels per day of bitumen production were possible. There was also success in predicting the quantities of steam required. In early analyses, the permeability of the reservoir was assumed constant and non-condensible gas was ignored.
The effects of reservoir layering are discussed and it is proposed that, in layered reservoirs, with permeability ratios less than about 2, the height average permeability should be used in the Lindrain equation.
Several authors have pointed out that when dissolved gas is included in their numerical simulation models, it tends to accumulate in the steam chamber, particularly towards the top, and inhibit the process by lowering the dew point of the steam. In some cases, this appears to choke the process and severely limit production and recovery. On the other hand, it has been appreciated that the accumulation of gas, and even its intentional addition to the steam, can be desirable because the lowering of the temperature of the steam chamber at the top reduces the heat, and hence the steam, requirement. The SOR is improved. The role of gas is discussed and it is shown that gas can move relatively easily, in small fingers, through the reservoir beyond the steam chamber. This allows the purging of gas from the chamber and also the pressure support of the chamber by gas flowing from the exterior. The intrusion of gas into the region above a rising chamber raises the pressure and tends to push oil downwards"the "Steam and Gas Push." Varying the steam injection rate can control pressure and allow the optimization of the gas content of the chamber. Results from a new computer program, "HOTSTEAM," are discussed. Unlike its predecessor, "HOTWELL," the new program allows the injection rate of the steam to be scheduled and it also provides for the support of the chamber pressure by gas"either from the reservoir or from injection. The program includes a continuing analysis of the production ell hydraulics and predicts the WHP as a function of time for natural lift.

Introduction
The Steam Assisted Gravity Drainage Process (SAGD)(1, 2) is finding increasing application for the in situ recovery of Canada's tar sand and bitumen deposits(3). This paper describes new concepts and ideas for the optimization of the process.

The SAGD Process
In the SAGD process, steam is injected, usually from a horizontal well, into a growing steam chamber. Oil drains, driven by gravity, from the heated region around the chamber to a horizontal production well placed low in the reservoir.
Use of Evaporation for Heavy Oil Produced Water Treatment
Authors: Heins W. , Peterson D. 
Published: March 2010

Abstract
Heavy oil recovery processes have traditionally used "once through" steam generators (OTSG) to produce high pressure steam for injection into geological formations containing heavy oil. The heat given up by the condensing steam fluidizes the heavy oil and allows the oil/water mixture to be brought to the surface. The oil is recovered as product and the water, referred to as produced water, is de-oiled and treated for feedwater to the OTSG. The typical treatment method for produced water is warm or hot lime softening (WLS or HLS), filtration, and weak acid cation exchange (WAC).
An alternative method of produced water treatment is vertical tube, falling film, vapour compression evaporation. This method:eliminates physical-chemical produced water treatment;results in lower life cycle costs;does not produce any softener sludge for disposal;minimizes the number and volume of waste streams requiring disposal;requires fewer maintenance materials and less maintenance labour;reduces the required amount of produced water de-oiling equipment;dramatically increases OTSG feed water quality, improving OTSG reliability; and,provides increased system availability and reliability. For steam assisted gravity drainage (SAGD) processes, which require 100% quality steam, it has the added advantage of producing water of sufficient quality for use in standard packaged boilers in lieu of OTSG. Packaged boilers are less expensive than OTSG, produce a much smaller liquid blowdown stream, and result in a boiler feed system which is 20% smaller than that of an OTSG.

Introduction
Heavy oil recovery requires large volumes of water commensurate in volume to the production of oil that it yields. Water is used in the form of steam to heat the geological formations that hold the oil. The oil is fluidized by the condensing steam and the oil/water mixture is pumped to the surface. The oil and water are separated. The oil is recovered as product and the water, referred to as produced water, is de-oiled and treated for reuse in the steam generator.
Traditionally, "once-through" steam generators (OTSG) have been used to produce 80% quality steam (80% vapour, 20% liquid) for injection into the well. A relatively new heavy oil recovery process, steam assisted gravity drainage (SAGD), requires 100% quality steam to be injected into the well (i.e., no liquid water). To produce 100% quality steam using OTSG, a series of vapour-liquid separators are required to separate the liquid water from the steam. The 100% quality steam is then injected into the well.
For both SAGD and non-SAGD applications, the produced water can generally be characterized as predominantly sodium chloride brine with high silica and minimal calcium and magnesium. High alkalinity, or carbonate, is present as well. The produced water generally contains about 4,000 mg/l total dissolved solids but can be much higher depending on the geological contribution. Dissolved and emulsified organics (oil) are present at a variety of levels, depending on the oil separation processes used.
Impacts of Gas on SAGD: History Matching of Lab Scale Tests
Authors: Yuan J.Y. , Law D.H.S. , Nasr T.N. 
Published: March 2010

Abstract
This study addresses the importance of initial GOR in SAGD heavy oil recovery operations. By history matching two laboratory scale experiments one with dead oil and the other with live oil we corroborated the theoretical and numerical prediction that gas would accumulate at the front of a steam chamber. This gas accumulation could slow down oil production as well as heat loss to the overburden. It is suggested that monitoring gas production during SAGD field operations may be critical for the investigation of impacts of gas, and for developing strategies for performance improvement.

Introduction
It was generally believed that gas could have positive impacts on SAGD operation. The negative impacts of gas on SAGD operation have also been noticed, but are usually considered minor(1–15). Recently, however, a theoretical and numerical study has shown that the negative impacts of gas on SAGD could be critical(16).
Two lab scale experiments concerning this issue have been conducted at Alberta Research Council. One was with dead oil and the other was with live oil. Results of these experiments were then history matched and analyzed using CMG's thermal reservoir simulator, STARS. In this report, we summarize the results from the study.

Experimental
The physical model was a rectangular stainless steel cell 80 cm in length, 24 cm in height, and 10 cm thick. The cell was packed with 220 Darcy Ottawa sand saturated with water and bitumen. The production well was placed at the centre across the length, 2.2 cm above the bottom of the cell and parallel to the thickness of the cell. The injection well was placed 5 cm above the production well. The cell was carefully wrapped with multiple layers of Nomax insulation. Two layers of Nomax and one layer of 1.9 cm thick plywood were used for the front wall and for the back wall. The heat transfer coefficient for one layer of Nomax was 0.08184 J/cm2-min- °?C and for one layer of plywood was 0.02684 J/cm-2 min- ° C. The cell was confined in a pressure vessel filled with nitrogen so that the overburden pressure of the cell was controlled. The viscosity of the dead oil used in the two tests was 32,500 cP at 15 °C, and was a sample from Cold Lake.
In the dead oil experiment, the initial cell pressure was 2,168 kPa and the initial cell temperature was 22 °C. The sandpack porosity was 36.7%. The initial oil saturation was 87%. The steam was slightly superheated and injected at an average rate of 33 cc/min, except during the first 10 min. During the first 10 min, steam was circulated into the injection and production wells, with the steam injection rate being at an average value of 68 cc/min. The experiment lasted 450 min.
In the live oil experiment, the initial cell pressure was 2,184 kPa and the initial cell temperature was 22 ° C. The sandpack porosity was 36.3%. The initial oil saturation was 89%.
Underground Gas Storage in a Partially Depleted Gas Reservoir
Authors: Soroush M. , Alizadeh N. 
Published: March 2010

Abstract
The main objective of this study is to perform a real case study of an Iranian gas condensate reservoir for the purpose of underground gas storage. Doing such a study for this reservoir will aid in the development of this technology and will also demonstrate a new concept for underground gas storage in partially depleted gas reservoirs. After gathering some data about the reservoir and preparing a geological model for the field, a simulation plan was considered for this field. A geostatic model was converted to a dynamic one by assigning reservoir fluid and rock data. Finally, a compositional model of the reservoir was prepared and verified to be accurate through a history matching process. After verifying the accuracy of the model and validating it, different scenarios for underground gas storage were developed. Depletion and gas storage scenarios were constructed for the field and results were obtained. Gas storage in a partially depleted gas reservoir was also considered in these scenarios for developing this field. After comparing different scenarios, some practical results were achieved and the best scenario for developing this field was chosen.

Introduction
An underground gas storage system can be defined as a combination of a constant supply with a variable demand for economic advantage(1). In other words, it helps to combine low summer season demand and high winter season demand to ensure that supply is maintained as a constant. The whole process is comprised of injecting natural gas or (rarely) other gases into the subsurface reservoir during periods that demand falls below the gas supply. When demands exceed the supply, the gas will be withdrawn from the reservoir. Fluctuating demand, due to temperature and climate, makes it necessary in many cases for the pipelines that inject or withdraw the gas be used efficiently(2). It also helps to have effective delivery during peak demand. This process can also be adapted to producing oil or condensate and can be considered as an IOR method(3). Increasing demand for gas in many areas of the world make storage plan development and effective use of existing storage sources a priority to ensure engineering and economic advantages. Figure 1 illustrates the relationship between natural gas supply and demand and clarifies the importance of storing gas during low demand periods in order that it may be used in high demand periods.

Reservoir Summary
A gas condensate reservoir that is located in central Iran is chosen for the purpose of underground gas storage. This field was
FIGURE 1: Natural gas supply and demand(2). Available in Full Paper.
discovered in 1955 and production started in 1959. It has a structure that is a northwest-southeast trending anticline approximately 25 km long and about five km wide. The structure was investigated by surface and seismic surveys and eight wells were drilled in the field. The production zone is in a formation of Oligo-Miocene limestone and is marly lime. The top of the producing zone is approximately at 5,200 ft.
A Model of Slurry Flow in a Fracture
Authors: Eskin D. , Miller M.J. 
Published: March 2010

Abstract
An accurate calculation of slurry flow in a fracture is an important issue for fracture design. A model taking into account particle dynamics on a micro-level has been developed. The model shows that the slurry dynamics, to a significant extent, is governed by particle fluctuations generated in a high shear-rate flow. Particles migrate from high shear-rate zones at the fracture walls towards the fracture centre. Thus, a slurry flow is characterized by non-uniform concentration across a fracture. Low solids concentration near the walls leads to reduction of slurry-wall friction compared to that predicted by a model not taking particle migration into account. Reduction in the friction leads to a significant decrease in the pressure gradient and the net pressure, respectively.

Introduction
Hydraulic fracturing is a complicated but well-studied technology for well stimulation(1). There are a number of computational codes for calculating technological parameters of a fracturing procedure. Such codes solve equations describing slurry hydrodynamics coupled with equations modelling formation fracturing. Since the percentage of fracturing job failures is high (above 30%), it is important to enhance the accuracy of modelling of different components of hydraulic fracturing to make this procedure a more reliable operation. In the current research, we suggest a model of slurry flow in a fracture taking into account an important effect of proppant migration to the fracture centre.

Model
Slurry flow moving in a fracture is usually characterized by a high mean shear rate (up to γm = um/w= 200 1/s), where um is the mean (superficial) slurry velocity and w is the fracture width. In our analysis, we will consider a steady-state slurry flow in a channel of a constant width. We also neglect impact of fluid leakoff into the formation on slurry dynamics.
Many fracturing fluids used in practice are characterized by the power-law rheology. Engineers usually employ a known solution of the Navier-Stokes equation for power-law slurry(1) obtained by assuming that particles have the same velocity as a fluid and that the concentration of solids is uniformly distributed across a fracture. Lattice-Bolzmann computations have shown that in a high shear rate slurry, flow particles fluctuate(2).
For the present study, the kinetic theory of granular flows(3) was employed for flow modelling. The kinetic theory assumes that particles collide with each other moving like ideal gas molecules and the velocity distribution of particle fluctuations is Maxwellian. The key parameter of this approach is the granular temperature determining intensity of particle fluctuations:
Equation 1 Available in Full Paper.
where &lt; υ2s&gt; is the mean-square fluctuation velocity of a particle.
An equation of a granular energy balance for a flat channel is written as(4):
Equation 2 Available in Full Paper.