bluuebunny/crossref_metadata_2025_split huggingface dataset:
Effect of Viscosity and Diffusion Coefficient on the Kinetics of Bubble Growth in Solution-Gas Drive in Heavy Oil
Authors: Kumar R. , Pooladi-Darvish M.O. 
Published: March 2010

Abstract
Some of the heavy oil reservoirs in Alberta and Western Saskatchewan show anomalously high primary recovery and high flow rate under solution gas drive. Several theories have been proposed for the anomalous behaviour. However, only a few theories look at the basic physics of the problem and find out the reason for this favourable behaviour.
The process of solution gas drive involves nucleation of gas bubbles followed by bubble growth and finally flow of gas. In his work, the aspect of bubble growth is studied in heavy oil and in light oil. A numerical model is developed, including the hydrodynamic and mass transfer effects to investigate the effect of viscous and diffusional forces on bubble growth.
An objective of the paper is to show that the effect of oil viscosity on bubble growth might be insignificant, even for heavy oils. A secondary objective is to examine the validity of the popular rowth model of R(t) = atb, when both diffusional and hydrodynamic forces are acting. The case of a gradual decline in pressure is studied, which more closely simulates the reservoir condition, and is compared with a step decline in pressure. It is found that the constants a and b in the above model need to be found for the conditions of interest; they depend on oil-type, rate of pressure drop, mass transfer boundary condition, etc. In another part of the paper, the gas phase growth during the solution gas drive experiment is modelled and the effect of various parameters, such as viscosity, depletion rate and diffusion coefficient, on the process is studied.
It is found that, in a constant volumetric rate of depletion process, the system compressibility might remain unchanged for some time, even after bubbles have nucleated and while they are growing. Hence, the maximum supersaturation observed does not have to correspond with the nucleation pressure.

Introduction
The process of solution gas drive involves nucleation of bubbles in oil as the pressure falls below the bubblepoint pressure, following which the bubbles grow. During growth, the bubbles come in contact with each other and, with the breaking of the lamella, coalesce to form interconnected gas bubbles, often with multiple branches.
The process of solution gas drive in heavy oil reservoirs shows a number of anomalies when compared to that in a light oil reservoir. A number of theories(1-7) have been proposed to explain this behaviour of the heavy oil reservoir. However, only a few look at the basic physics of the problem. In this paper, an attempt has been made to study bubble growth with specific application to the solution gas drive process by looking at the physics of bubble growth and study the effect of viscosity and other parameters. As a first step, a single bubble growth in bulk is considered and the effect of the porous medium is not included. The bubble growth in light oil, is compared with that in heavy oil, and the reason for the differences sought.
Reservoir Paraffin Precipitation: The Oil Recovery Challenge in Dom Jo?o Field?
Authors: Mezzomo R.F. , Rabinovitz A. 
Published: March 2010

Abstract
Dom Joao Field, located at Reconcavo Basin in northeastern Brazil, has been under production for more than 50 years. From the very beginning in 1947, exploitation has been plagued with problems that standard geology and reservoir engineering practices were not able to cope with. With an OOIP of 113 MMm3 of 38 °CDATA[API paraffinic crude, the current recovery factor stands at only 15%, in spite of the early implementation of waterflooding. Three major reservoir studies by different organizations, Petrobras included, were conducted over the years with significant impact on the geological model and appraisal of the original volumes, together with recommendations as to the variation in the injection and production patterns. They were implemented accordingly but with limited success and, other than the heterogeneity of the reservoirs in the main Sergi Formation, no suitable explanation was found for the poor recovery performance, not to mention a solution to the problem. The size of the target oil and the constant threat of field abandonment, led to the approval of a research project in late 1993 as part of the portfolio of PRAVAP, Petrobras Strategic Advanced Oil Recovery Program. Its goal was twofold: verify the assumption of paraffin precipitation in the reservoir as the cause of the low recovery factor, and eventually put to the test recovery strategies that would ensure the economical exploitation of the shalloweposits of paraffinic crude in Reconcavo Basin. This paper summarizes the major accomplishments of this project throughout the 3 1/2 years of research and development and the corresponding IOR field implementations.

Introduction
As reported by Leite(1), Dom Joao Field, the second oldest commercial accumulation in Brazil, was discovered in March 1947. Situated in the southwestern part of Reconcavo Basin in Bahia State, Brazil, it is 23.5 km long and 0.6 - 3.5 km wide for an area of 47.3 km(2) (Figure1). Structurally, it is a slightly dipping (1 - 5 °CDATA[) horst, limited by a major fault zone with 400 to 500 m of displacement in the West, and smaller ones in the East. Two thirds of the field are located offshore in Todos os Santos Bay, at an average water depth of 3 m. It produces from the 8 zone (C-J) Sergi formation at depths between 146 m and 376 m. C zone, with an average net pay of 10 m, is the major producer. For management purposes only, the field is divided into Dom Joao Onshore and Dom Joao Offshore. Also, due to a series of normal faults across the structure, the offshore part of the field is further divided into Northern Dom Joao Offshore and Southern Dom Joao Offshore. General data on Dom Joao Field is given in Table 1. Over the years, a total of 828 wells were drilled in Dom Joao Field to tap an original volume of oil in place of 113 MMm3. Yet, after more than 50 years of exploitation, the recovery factor stands at barely 15﹪ OOIP.
Upgrading Athabasca Tar Sand Using Toe-to-Heel Air Injection
Authors: Xia T.X. , Greaves M. 
Published: March 2010

Abstract
The unique operation of the THAI (Toe-to-Heel Air Injection) process, enables very high oil recovery and substantial in situ upgrading. Both thermal upgrading (non-catalytic) and also catalytic upgrading, in which a catalyst is emplaced along the horizontal producer well, were investigated. 3D physical model experiments were conducted on virgin Athabasca tar sand bitumen to investigate dry and wet combustion performance. These results were compared against those from a steamflood test, which was subsequently followed by air injection. Excellent ignition, very stable combustion propagation and thermal upgrading of nearly 10 ° API were achieved using Athabasca tar sand. Additional upgrading was achieved using an in situ catalyst. THAI has the extra advantage that some hydrogen is generated in situ, providing further significant upgrading via hydroconversion. There are also substantial environmental benefits because of the large reductions in sulphur and heavy metals in the produced oil. Furthermore, oil is produced without "displacement delay," immediately ahead of the combustion front. The oil recovery using THAI was greater than 75% OOIP.

Introduction
The world's conventional crude oil production is expected to reach its peak in the second decade of this century and enter a permanent decline phase(1). The composition of the oil barrel is getting heavier, and diluent blending "stop-gaps," assisted by very limited coker upgrading capacity will, eventually, be insufficient to cope with the increasing demand for light oil. Historically, heavy oil trades at a substantial discount to that of premium light crude oil. Therefore, it has lower economic value and also market potential, unless new technology is developed to upgrade it to lighter oil, in an economic manner.
The Athabasca Tar Sand deposit of northeastern Alberta, Canada, is one of the largest reserves of bitumen in the world. These are estimated to be 212.9 ??109 m3 (1,339 ?109 bbl)(2). Although about 10% of the bitumen reserves are mineable, the rest of the Athabasca Tar Sands have to be exploited by in situ recovery technology. A number of in situ oil recovery methods, such as steam assisted gravity drainage (SAGD)(3) and in situ combustion (ISC)(4, 5), have been extensively studied, both in the laboratory and in field tests.
In situ combustion (ISC) is a thermal EOR method, in which a small fraction of the oil (or coke) in the oil layer is burned in order to mobilize the unburned fraction. Due to the strong exothermic oxidation reactions between hydrocarbon (or coke) and oxygen, the temperature of the oil-bearing matrix in the combustion zone is 500 to 700 °C, which is much higher than in steam flood processes (150 to 250 °C). High temperatures are very favourable for tar sands and heavy oil reservoirs, because not only is the oil viscosity reduced by several orders of magnitude, but the heavy residue is also thermally cracked to lighter compounds.
Strategic Upstream R&D Collaboration
Authors: Dingle Howie 
Published: March 2010

The Canadian upstream oil and gas industry-like any other non-renewable resource industry-is ultimately a "sunset" industry. But not yet!

Renewal Through R&D
Our traditional mechanism for renewal (Figure 1) has been to explore for and to develop new reserves. Estimated undiscovered conventional liquid in the Western Canada Basin is one-eighth the unrecoverable volume remaining in discovered pools. Estimated undiscovered conventional liquids in the frontiers may be large but has prohibitive development costs which have kept existing discoveries from production. The undiscovered natural gas resources in both the Western Canada Basin and the frontiers face supply cost vs price hurdles at least through the balance of the decade.
Our known heavy oil and oil sands bitumen in place are a worldclass hydrocarbon resource with prohibitive supply cost hurdles for the foreseeable future.
This is a challenging, but not an impossible scenario. Canada has the hydrocarbon resources-discovered and potential-to sustain a domestic production industry well into the 21st Century. We also have the economic and scientific will to fulfill that potential. R&D is crucial for renewal for several reasons. First, it will enable us to control and reduce ever-increasing unit operating costs in our existing operations. Secondly, it will enable us to maintain our aging infrastructure-even in the face of ever more stringent environmental and safety requirements. R&D is also necessary to extend the life of our existing pools by facilitating the enhancement existing recovery processes. It is a critical tool, moreover, in renewing hydrocarbon reserves through the development of new recovery processes, and through the development of technologies to enable the development of the inherently high supply cost frontier and oil sands resources. Finally, R&D is necessary to add value to our commodity products in order to retain our existing markets in the face of international competition.

Changing the R&D Paradigm
Historically, with real growth in energy prices and with reserves additions exceeding production, upstream research and technology development has been fragmented and duplicated. It has been aimed at obtaining competitive advantage with the local industry, in an effort to capture the largest possible piece of a prize which has failed to materialize. The industry as a whole has spent a great deal of money on R&D - AOSTRA estimates that over a billion dollars has been spent on oil sands R&D alone. Thus, the level of R&D effort is not the problem so much as the way in which it has been conducted.
Collaborative research and technology development must now be the major mechanism for renewal of our domestic upstream industry. Today, our principal competition is global-low supply cost crude from overseas. Our domestic industry is not competitive in the world marketplace, as is evident from our returns on investment through the 1980s.
A Case Study of Foamy Oil Recovery in the Patos-Marinza Reservoir, Driza Sand, Albania
Authors: Bennion D.B. , Mastmann M. , Moustakis M.L. 
Published: March 2010

Abstract
With a current recovery of only 5%, Albania's largest oilfield, Patos-Marinza, (first commercially produced in 1939) still contains potentially more than 100 MMbbl of reserves of 10 to 12 ° API oil at a depth of 1,600 m. A consortium consisting of Albpetrol Albania, Preussag Energie (Germany), Premier Oil (Britain), and the IFC (the private sector arm of the World Bank) are making plans to improve oil recovery in the area.
Test wells producing 1 to 2 m3/d yielded large rate improvements to over 30 m3/d using "progressive cavity pumps" up to 30 m3/d with producing sand cuts around 10 to 35%. PVT analysis of the oil, with a relatively high solution GOR of 31 m3/m3, shows a strong tendency to foam (gas in microbubbles without forming a continuous gas phase) below the bubble point, near the initial reservoir pressure. Core tests with different depletion rates resulted in primary oil recoveries of greater than 30%.
This paper discusses the detailed suite of laboratory measurements used to examine the Driza crude oil, in the context of present theories of foamy oil and cold heavy oil production with sand (CHOPS).

Introduction
The Patos-Marinza oilfield is an onshore field located east of the city of Fier in South Central Albania (Figure 1). It occupies an area of approximately 24,000 hectares and was discovered in 1926, with commercial oil production starting in the early 1930s. Development to the north continued with drilling of over 2,300 wells, reaching the boundaries of the field in the late 1980s.
The main sandstone reservoirs dip at 8 ° to 13 ° from an outcrop in the South containing mineable tar sands to the original oil water contacts at 1,800 m in the north. There are multiple stacked sand reservoirs of Upper Miocene (Messinian) age, the most important ones being the Gorani, Driza, and Marinza (top to bottom). The Driza reservoir contains the majority of the OOIP and reserves. It consists of up to six sand layers numbered from top to bottom, with D1 being the main sand continuous throughout the field. The Driza is a suite of unconsolidated sandstones with porosity of 25 - 28% and net pay varying areally from 7 to 95 m (south to north).
Oil gravity also varies throughout the field depending on the depth of the reservoir and the type of formation. The Marinza oil (north) has a gravity up to 825 kg/m3 (40 ° API) due to greater depths and a closer position areally to the source rock. The oil gravity in the Patos area (southern half of the field) is about 998 kg/m3 (11 ° API) with dead oil viscosity over 9,000 mPa.s under reservoir conditions.
Due to the unfavourable fluid properties, oil recovery to date in the entire reservoir amounts to less than 5% under depletion drive. The wells with a 2.5 acre spacing generally produce less than 1 M3/d of oil with tubing insert pumps landed halfway to bottom due to equipment limitations.
Lab-Scale Numerical Simulation of SAGD Process in the Presence of Top Thief Zones: A Mechanistic Study
Authors: Law D.H.S. , Nasr T.N. , Good W.K. 
Published: March 2010

Abstract
There is a major concern in the steam-assisted gravity drainage (SAGD) process 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. The objective of this numerical study is to investigate the mechanisms that govern the oil and steam loss during the SAGD process in the presence of a top water zone or a gas cap.
The reservoir model, STARS, developed by the Computer Modelling Group (CMG) Ltd. was first validated based on history matching of two 3D SAGD laboratory experiments with a top water zone and a gas cap, respectively. The experiments that were designed to mimic SAGD processes in the Athabasca region were conducted at field conditions of reservoir pressure and steam injection temperature. It was found that STARS was capable of history matching the top water and gas cap experiments. Therefore, it is believed that the numerical simulation captured the major mechanism of oil movement from the oil zone into the top thief zones as observed in the experiments.
Lab-scale numerical sensitivity study indicated that oil movement from the oil zone into the top thief zones occurred when a very small pressure gradient existed between the oil zone and the top thief zone (e.g., &lt; 10 kPa/m). Higher-pressure gradients resulted in more oil and steam movements into the top thief zone, less oil production, and a higher steam-oil ratio.

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 the economic recovery of any oil. 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.
A case in point is the Surmont oil sands lease, which Gulf planned to develop with a SAGD pilot starting in June 1997 followed quickly by commercial development.
A Supplemental Discussion of Productivity Formulae of Horizontal Wells
Authors: Lu J. , Lin T. , Rogers R. , Lu T. 
Published: March 2010

Abstract
This paper presents a supplemental discussion of productivity formulae for horizontal wells using a uniform line sink model. Formulae are given for the productivity of horizontal wells in steady state in an infinite lateral extent drainage reservoir with impermeable top and bottom boundaries. This paper also focuses on the effects of different boundary conditions on the productivity of a horizontal well. Significant differences in the productivity of a horizontal well in a reservoir with different drive mechanisms are demonstrated.

Introduction
In Reference (1), Jing Lu presented new productivity formulae for horizontal wells, which are derived from the three-dimensional solution of the Laplace Equation, as opposed to two-dimensional or pseudo-three-dimensional solutions used in the previous Equations in References (2), (3), (4), and (5). Lu's formulae are given for the productivity of horizontal wells in ellipsoidal drainage reservoirs and infinite lateral extent drainage reservoirs with gas cap or bottom water.
In this paper, formulae are given for the productivity of horizontal wells in steady state in an infinite lateral extent drainage reservoir with impermeable top and bottom boundaries. The significant effects of different boundary conditions on the productivity of a horizontal well are also demonstrated.

Horizontal Well Model
Figure 1 is the model of a horizontal well in an infinite lateral extent drainage reservoir.
The following assumptions are made:The reservoir is horizontal, homogeneous, anisotropic, and has constant Kx, Ky, Kz permeabilities, thickness H, and porosity Φ. The reservoir is with infinite lateral extension, i.e., the boundaries of the reservoir in the horizontal directions are so far away that the pressure disturbance does not travel far enough to reach the boundaries during the well production.The reservoir pressure is initially constant. The pressure remains constant and equal to the initial value at an infinite distance from the well. The reservoir is bounded by top and bottom impermeable formations.The production occurs through a well of radius Rw, represented in the model by a uniform line sink located at a distance zw from the lower boundary. The length of the well is L.A single-phase fluid, of small and constant compressibility Cf, constant viscosity µ, and formation volume factor B, flows from the reservoir to the well at a constant rate Q. Fluids properties are independent of pressure.

Equations for Horizontal Wells
As Figure 1 shows, the horizontal well is a uniform line sink in 3D space, and the coordinates of the two ends are (-L/2, 0, zw) and (L/2, 0, zw). We suppose the point (xO, 0, zw) is on the well line, and its point convergence intensity (point flow rate) is q. In order to obtain the point convergence pressure of (xO, 0, zw), we have to obtain the basic solution of the partial differential equation below:
Equations (available in full paper)