bluuebunny/crossref_metadata_2025 huggingface dataset:
Recovery Mechanisms in Fractured Reservoirs and Field Performance
Authors: Firoozabadi Abbas
Published: March 2010

Fractured petroleum reservoirs provide considerable challenge in studyingnatural depletion, immiscible gas injection, miscible gas injection, and waterinjection. In this overview, certain key aspects of two-phase flow in relationto gas injection and water injection in fractured reservoirs are reviewed. Onemain conclusion from the review is that the field performance can be veryefficient by water injection in some weakly water-wet fractured eservoirsdespite the poor recovery in the laboratory by the conventional imbibitiontests.

Introduction

Fractured hydrocarbon reservoirs provide over 20 % of the world oil reserves andproduction. Examples of the prolific fractured petroleum reservoirs are:the Asmari limestone reservoirs in Iran,the vugular carbonate reservoirs in Mexico, andthe group of chalk reservoirs of the North Sea.

These prolificreservoirs produce more than five million barrels of oil a day; their commonfeature is a long life span, which could last several decades. There are alarge number of other fractured hydrocarbons reservoirs that may have featuresvery different from the above reservoirs. Examples of such reservoirs are the Austin chalk field and the Keystone (Ellenberger) field in Texas, and the Tempa Rossa field in Italy. In the Keystone field, the average matrix porosity isaround 2.5% the Austin chalk and Tempa Rossa also have very low porosity. Onthe other hand, the average matrix porosity of the Ekofisk chalk field in the North Sea is around 35%.

Fractured reservoirs can be classified into three different groups. For groupone, the bulk of the hydrocarbon resides in the matrix and fracture pore volume(PV) is very small in comparison to the matrix PV. The Ekofisk field in the North Sea is an example of this group(1). In group two, most of thehydrocarbon is in the matrix, but fracture PV could be as high as 10 to 20%.The Asmari limestone reservoirs are an example of the secondgroup(2). For group three, more than half of the hydrocarbon residesin the fracture; in some cases, the contribution of the matrix can benegligible. The Keystone (Ellenberger) field in Texas is an example of afractured reservoir where most of the hydrocarbon is from thefractures(3). There are very few reports of the productionperformance of group three in the literature. For all three groups, the matrixpermeability is often low-of the order of several md to less than 0.01 md. Theeffective permeability due to fractures increases from one to several orders ofmagnitude. In some of the reservoirs of group three, the productive life variesfrom less than one year to several years. The ultimate recovery from fracturedreservoirs varies widely- from less than 10 % to over 60%. The recovery factorin group three could vary from 10% to over 60% the recovery factor of 10 % ismostly from the fracture and rock compressibility, and the recovery of 60 % ismainly from gravity drainage. Later we will study the key factors that affectrecovery performance of fractured reservoirs.
Numerical and Experimental Modelling of the Steam Assisted Gravity Drainage (SAGD)
Authors: Sasaki K. , Akibayahsi S. , Yazawa N. , Doan Q. , Ali S.M. Farouq
Published: March 2010

For complex petroleum recovery processes, an experimental investigation isusually performed with a numerical simulation to study the recoverymechanism(s). In this paper, both physical and numerical simulations of thesteam assisted gravity drainage (SAGD) process were performed. One of theobjectives of the numerical investigation was to determine the match betweenumerical results with data generated from scaled model experiments. The Computer Modelling Group's (CMG) STARS? thermal simulator was used. Resultsfrom the numerical simulation were found to be in reasonable agreement withthose obtained from the experiments for oil production rates, and cumulativeoil production. In addition, the steam chamber volume and temperaturedistribution were also examined. ffects of different parameters, such as steaminjection pressure, vertical separation between injection and production wells, nd reservoir thickness, on the performance of the SAGD process ereinvestigated. They were observed to have the same effects on both experimentaland numerical results. The numerical simulator was also used to study theinfluence of rock and fluid properties, such as oil viscosity, permeability, porosity, and the mount of heat loss from the reservoir to thesurroundings.

Introduction

The steam assisted gravity drainage (SAGD) process was developed by Butler(1), and is illustrated in Figure 1. It has been applied inseveral projects, including the Underground Test Facility (UTF) and has shownpromise of achieving high recovery (more than 50 % of OOIP in some cases).

Many experimental and numerical studies of the SAGD process have been carriedout over the last ten years, on different aspects of the process. One of therecent numerical studies was presented by Chow and Butler(2). Theyfocused on history matching the oil recovery and the steam temperatureinterface position with those observed in the SAGD experiments by Chung and Butler(3).

In the present study, numerical history matching of the experimental data, suchas the oil production and the steam chamber temperature contours [Sasaki etal.(4)] is the main focus. Furthermore, time to establish initialcommunication between the two steam injection and production wells (steambreakthrough time) was investigated. The physical and operational conditions inthe experimental study were different, compared to those used in Chung and Butler's experiments(3). They included a pressure drop of?Pi = 20 kPa, permeability of k =142 D; no pre-heating was employed.The experiments were configured to examine phenomena associated with the risingchamber. More details are provided in the following, for both experimentalinvestigation and numerical simulation.

Description of the Experimental Model

Several 2D visual, scaled physical models were used in the experiments. Theywere designed to represent a vertical section of a heavy oil reservoir. Themodels had sidewalls of acrylic resin (of 20 mm in thickness).
Some Recent Developments in SAGD
Authors: Butler Roger. M.
Published: March 2010

Steam Assisted Gravity Drainage (SAGD) is being used increasingly for the recovery of bitumen and heavy oil in Canada. Four large SAGD projects are under construction in Athabasca and two others have been announced. These projects are expected to produce bitumen economically and with a recovery greater than 50%. Productivity will be close to 1000 B/d per well pair. There are also many successful smaller, and growing, projects and pilots in Athabasca, Cold Lake and Lloydminster. Because of the rising costs of fuel it is desirable to reduce steam requirements for SAGD. Means for doing this include cogeneration of steam and power, alternate fuels, choosing better reservoirs, improved heat recovery, and the newer related processes, SAGP and Vapex.

In Steam Assisted Gravity Drainage (SAGD)(1), Steam and Gas Push (SAGP)(2), and Vapour Extraction (Vapex)(3) the oil isduced in viscosity and produced by gravity drainage to horizontalells placed low in the reservoir. As the oil drains, the vacatedreservoir pores are filled largely with gas/steam in SAGD, steam lus non-condensible gas in SAGP and solvent vapour plus noncondensible gas in Vapex.

A common feature of the three processes is that the use of long horizontal wells combined with the reduced viscosity of the produced oil allows the production of oil with essentially no by-pass of free gas. In suitable reservoirs economic rates are achieved whereas with conventional wells or without adequate viscosity reduction there would be intolerable gas coning. High recoveries are obtained because of the systematic nature of the drainage. Since the author's earlier paper in this series(4) there has been a great increase in the interest in this subject and there are now many substantial field projects in various stages of planning and construction.

Advanced Commercial SAGD Projects In Athabasca

SAGD is at the stage where several major field projects to recover bitumen from Athabasca are either under construction or about to be. In most cases, the reservoirs are thicker than those that have been exploited previously and superior results are anticipated. The initial investment for large SAGD projects is of the order of $10,000 Canadian per B/d of capacity and the Steam Oil Ratio (SOR) is about 1.9 to 2.5. The supply costs for bitumen will probably be less than $10 Canadian per barrel, including return but excluding the fuel cost. This important cost is discussed later. Generally product lifting from the reservoir is by natural flow, a technique first demonstrated by Sceptre Resources and now used in several of the pilots. Four large commercial SAGD projects are described below. A recovery of over 50﹪ of the oil in place is expected in each. Figure 1 shows the approximate locations of the projects discussed below.

Alberta Energy Company (AEC) Foster Creek (T70 R4 W4M)(5)

This is a commercial expansion of AEC's pilot project, which produces 2,000 B/d from three SAGD well pairs.
THAI-New Air Injection Technology for Heavy Oil Recovery and In Situ Upgrading
Authors: Greaves M. , Saghr A.M. , Xia T.X. , Turtar A. , Ayasse C.
Published: March 2010

THAI-"Toe-to-Heel" Air Injection, is a new EOR process, which integrates advanced technology and horizontal well concepts, to achieve a potentially very high recovery of heavy oil. It can also realize very substantial in situ upgrading by thermal cracking, producing upgraded oil to the surface. The process operates in a gravity stabilized manner by restricting drainage to a narrow mobile zone. This causes the flow of mobilized fluids to enter directly into the exposed section of a horizontal production well. The process can be operated on primary production, asnew technology, as a follow-up to existing technologies, or asa co-process where the advantages of high thermal efficiency are equired. This is achieved by concentrating the energy required for oil mobilization, recovery and thermal upgrading in the reservoir. Combined with clean technology design, THAI offerspathway, to future economic success for the heavy oil industry. Three-dimensional, semi-scaled experimental tests on light "Forties Mix" oil (30.7 °CDATA[API), Clair, West of Shetlands medium heavy oil (20.8 °CDATA[API), and heavy Wolf Lake oil (10.95 °CDATA[API) show that a well-controlled, narrow mobile oil zone is created just ahead of the combustion front. The width of this narrow zone depends on the characteristics of the heavy oil at reservoir conditions and the degree to which the very high viscosity of the cold oil seals the horizontal producer well. Well sealing can be augmented by a novel sleeve-back technique, which allows perforated downstream sections of the well to be shut-in. The application of this technique enabled the light oil test to mimic the operation of a heavy oil reservoir using THAI. Very high oil recoveries were achieved in the tests, up to 85﹪ OOIP. During wet in situ combustion (ISC), Wolf Lake oil was upgraded to 20 °CDATA[API, achieving a reduction in the cold oil viscosity from 100,000 mPas to around 50 mPas.

Introduction

Horizontal and multi-lateral wells are being introduced in ever increasing numbers to achieve further gains in reservoir productivity. Two hundred horizontal wells were drilled a decade ago. Now, one company has reported drilling more than 2,100 horizontalwells in North America(1). Advances have also been achieved in the depths drilled, reaching 8,761m(2) and lengths now reaching up to 11 km. Multi-lateral wells, with four or more side-tracks, are not uncommon and offer further optimization gains. Moreover, this technology will accommodate reservoir faults and problems of structural geology as regular design factors so that strategic placement of the well path is achieved. More recently, a new technique to control gas and water production rates by varying the fluid entry points has been successfully tested(3). The most important advantage of horizontal wells is the increase in the reservoir contact area compared to a vertical well. Horizontal wells have created new possibilities for the implementation of advanced IOR methods, especially in thermal recovery.
Mechanisms of Solution Gas Drive in Heavy Oil Reservoirs
Authors: Firoozabadi Abbas
Published: March 2010

Introduction

Solution gas drive in heavy oil reservoirs (with viscosity in the range of 10 to 1,000 poise and API gravity in the range of eight to 15), which is often referred to as cold production, has a long production history in Canada. In a recent review paper, Dusseault et al.(1) presented the information that more than 5,000 wells in Canada have produced heavy oil by cold production. In addition to Canada, cold production from heavy oil reservoirs has been practiced in Venezuela(2), China(3), and Oman(4). Recoveries from some of the heavy oil reservoirs by cold production are estimated to be as high as 20﹪. The high recovery is often associated with a low pressure decline rate in the reservoir and the slow increase of GOR in the two-phase below the bubblepoint, as well as geomechanical effects. Recoveries in the range of 10 to 20﹪ below the bubblepoint pressure are believed unusual for very heavy oils. In this overview, we will briefly review the literature and then provide some insight into the relevant mechanisms for cold production.

Literature Review

An early paper by Smith(5) set the stage for the understanding of cold production from solution gas drive in heavy oil reservoirs. In his work, Smith provides an analysis of solution gas drive in heavy oil reservoirs from the examination of field data. He attributes the high efficiency of solution gas drive in viscous oils to:a significant reduction (around one order of magnitude) in the oil viscosity due to formation of small gas bubbles in the oil,simultaneous flow of continuous oil phase and discontinuous gas phase in the form of tiny bubbles,an increase in absolute permeability due to sand production, andhigh fluid compressibility due to high gas bubble density in the oil. In order to validate some of the postulations by Smith, the bulk of research has focused on the socalled pseudo-single phase model. In the pseudo-single phase model, a new terminology has evolved to distinguish solution gas drive in heavy oil reservoirs. The so-called foamy oil terminology was introduced in 1992 by Sarma and Maini(6); it was defined as a viscous (heavy) oil containing dispersed gas bubbles. Claridge and Prats(7) used the term " foamy heavy oil" and " foamy crude" mainly to imply drastic reduction in the oil viscosity due to dispersed as bubbles. The term " foamy oil" has had a wide acceptance because the oil samples at the wellhead produced from the reservoirs seem to be in the form of oil-continuous foam, with the appearance of chocolate mousse, and may contain a large volume of dispersed gas bubbles. Hu et al.(3) report that the density of the produced oil from a heavy oil pilot well from the Henan oil field in China is about 0.58 g/cm3, while the density after all the gas has left the oil (which may take several days) is 0.95 g/cm3.
How to Compute the Permeability and Skin Factor of Low Pressure Water Zones
Authors: Szpunar T.
Published: March 2010

The paper presents a simple mathematical model which allows prediction of the behaviour of the water table in a low pressure water well which does not flow to surface. The derived relations enable computation of the permeability and skin factor of the water zone. Unlike the type-curve method used for interpretation of "slug test" data, the permeability and skin are computed using a straight-line approximation. The slope of the straight line and its intersection with the ordinate axis are used to interpret the test data. The presented method is very simple and yields unique results.

How to Compute Permeability and Skin

In low pressure water wells, the water table stabilizes at some depth below the surface. Such a situation is observed in water wells, some oil wells, hydrogeological wells and coalbed methane wells. "Slug testing"involves the sudden removal of some liquid from the well, and then analysing the water table behaviour (or pressure response) to determine the reservoir transmissibility. If the duration of flow from the reservoir is sufficiently long, liquid will continue to accumulate in the well until the pressure exerted by the liquid column in the well equals the reservoir pressure. The permeability and skin are evaluated by matching the measured pressure vs. time data or water level vs. time data to one curve among the family of theoretical curves. Mismatching ends up with erroneous results. The model presented here enables computation of the permeability and skin using a straight-line approximation through the conventional "slug test" data; i.e., it can be used for interpretation of DST flow period data. The relation (derived in the Appendix) used to compute the permeability and skin is:

Equation (1) Available In Full Paper.

z0 denotes the stabilized liquid level (which corresponds to original reservoir pressure), and z1 denotes the liquid level after some fluid is removed from the well at t = 0 (which corresponds to initial tubing pressure at the water zone level). z(t) is a current water level measured while the water table rises up in the well (corresponds to actual tubing pressure at the water zone level).

The following nomenclature is assumed in Equation (1):k = permeability of a water zoneh = thickness of a water zoneρ = fluid densityg = acceleration of gravityr w = tubing radiust = timeφ = porosity of a water zoneμ = fluid viscosityS = skin factor

Equation Available In Full Paper.

is a root of the following equation:

Equation (2) Available In Full Paper.

Where

Equation (3) Available In Full Paper.

As long as ct does not change with time, Equation (1) indicates

that a plot of

Equation Available In Full Paper. vs. t is linear with slope

Equation (4) Available In Full Paper.

permitting the calculation of permeability, k. The skin factor can be calculated by evaluating the point of intersection of the same plot at t = 0, given as D:

Equation (5) Available In Full Paper.
Progress in the In Situ Recovery of Heavy Oils and Bitumen
Authors: Butler R.M. , Yee C.T.
Published: March 2010

Most of Canada's trillion barrels of petroleum consists of bitumen, and to a lesser extent, heavy oil. This total may be compared with the total Canadian production of light-medium crude oil to date, which is only 12 billion barrels. Mining is effective for the production of bitumen, but is limited to the minor fraction of the resource that is shallow; also mining involves significant environmental difficulties.

The challenges of efficient in situ production are like those for other petroleum production activities:to find and define suitable reservoirs,to create conditions for oil to flow at economic rates, andto drain the reservoir systematically to obtain high recoveries.

This paper discusses the following in terms of production rate, recovery, energy requirements and economic factors. Each topic is a step, sometimes a sideways step, in the search for a means to achieve high rates and recovery within the bounds of economic constraints.Cold production using vertical wells and horizontal wells.Stimulation by wellbore heating.Cyclic steaming using conventional wells.Steam Assisted Gravity Drainage (SAGD).Steam and Gas Push (SAGP).Cyclic Steaming with horizontal wells.Vapour Extraction (Vapex).

Processes resulting in the displacement of oil by gas to a lower horizontal well show the most promise. The viscosity in the region around the horizontal well should be reduced to allow economic rates without gas coning.

In SAGD, injected steam heats the oil and fills the reservoir as it drains, and rates of 79 – 159 m3/d (500 – 1,000 B/d) can be achieved with bitumen recoveries greater than 50%. Heat savings can be achieved by building a substantial gas concentration within the depleted region (SAGP).

In Vapex, viscosity reduction is obtained by dilution with a olatile solvent; this is a promising approach for lower viscosity heavy oils.

Another promising approach is cyclic steaming with horizontal wells, combined with gas addition to the steam to maintain drive.

Introduction

As conventional oil reserves become depleted, interest continues to grow in the improved recovery and utilization of Canadian tar sands and heavy oil. The resources are enormous in magnitude, and there have been great strides in technology. One approach, the mining and upgrading of shallow Athabasca deposits has, with the success of the Suncor and Syncrude projects, already become a major source of Canadian oil. Major expansions to both of these projects, as well as other new tar sand mining projects are underway.

While mining overcomes the problem of moving the oil to the surface and of obtaining high recoveries, it requires the handling and disposal of vast amounts of solids and sludge, and it is only economic for the shallowest of deposits. The major part of the Canadian oil sand resource is too deeply buried for mining to be practical.

This paper is concerned with the recovery of bitumen and heavy oils by in situ methods, i.e., by means of wells drilled from the surface.
Comparison of Pressure Transient Behaviour of Composite and Two-Layered Reservoirs
Authors: Jordan C.L. , Mattar L.
Published: March 2010

In pressure transient analysis, often the geological model is not known, or is ambiguous. Many well tests can be analysed using a composite reservoir model which assumes that the flow capacity (k*h) near the wellbore is different from that away from the wellbore. There are many naturally occurring reservoirs that can legitimately be modeled this way because the transmissivity is indeed varying laterally. However, there are many more reservoirs which have a different flow capacity near the well as compared to the bulk of the formation, not because of lateral permeability changes, but because of layering. In these situations, it is the net pay and reserves, not necessarily the permeability, that is changing.

This paper compares the pressure transient behaviour of a multi-layer system with that of a composite system, and illustrates the similarities and the differences in their respective derivative signatures. It also investigates the extension of these two different models to pseudo-steady state forecasting. Even though the behaviour of these two systems may be similar during transient flow (which is the time domain of most well tests), the long-term performance is significantly different if the improper model is used (which is typically the time domain of many engineering and economic decisions). The role of the geological model in well testing and deliverability forecasting is discussed, as it can have a significant effect on some parts of the analysis, and an insignificant effect on other parts.

Introduction

Multi-Layered System

It is commonly known that if two or more layers of a reservoir are open to a wellbore, and are initially at a common pressure and constant drawdown, the general characteristics of the drawdown response is similar to that of a well producing from a single layer reservoir(1, 2). Specifically, each layer will contribute production which is proportional to its transmissibility (kh/ µ). Therefore, the semi-log slope (m) calculated from the infinite acting flow*?data will be nearly proportional to the sum of the individual layer transmissibilities (any modification of this slope would be due to unequal diffusivities or skin factors). For example, if a well is producing commingled at the wellbore from a layer of 2 m and a layer of 3 m net pay (both with a permeability of 20 mD), the semi-log analysis of the radial flow data (refer to Figure 1) will show a flow capacity of 100 mD.m

If one layer of a two-layer model is limited in drainage area, a depletion of the limited layer will eventually occur. Upon depletion of this layer, a semi-log straight line with a slope "m" that is inversely proportional to the transmissibility of the more extensive layer may be observed. On the derivative analysis, after the initial radial flow, a unit slope develops followed by a transition to a second radial flow characterized by the typical zero slope.
Modelling Sand Production Within a Continuum Mechanics Framework
Authors: Wan R.G. , Wang J.
Published: March 2010

The paper presents a continuum mechanics framework in which sand production can be modelled on the basis of an erosional mechanism. A representative elementary volume, comprised of three constituents namely solid, fluid, and fluidized solids, is chosen upon which mass balance and particle transport equations are written. The erosional process is described by a particle generation constitutive law. The coupled non-linear governing equations are finally solved using the finite element technique with a Newton-Raphson scheme. In order to illustrate the capabilities of the model, the evolution of controlling field variables, such as porosity, fluidized sand concentration, and pressure, are computed for a wellbore subjected to a pressure gradient corresponding to fluid draw down during pumping. In the case of anisotropic permeability conditions, sand production is at its peak value at different points around the wellbore, and there is a time lag between the times at which each point reaches its peak. This is due to the averaged fluid and fluidized sand fluxes being non-radial.

Sand production from unconsolidated formations occurs when the well fluid being produced under a high pumping rate dislodges a portion of the formation solids, leading to a continuous flux of formation solids. In Alberta, the formation from which the fluid (hydrocarbon) is being produced is oil sand, while the solids comingout with the fluid is sand, although solids can be produced from a variety of other formation types, such as sandstones. Sand in the well fluid can erode casing, pipes, and pumps, or plug the well if sufficient quantities are produced. The distinct periods of sand production in the well and reservoir life as pressure is being depleted were discussed by Morita et al.(1)

Introduction

There are a number of schemes to address sand production. Exclusion schemes involve the installation of gravel packs or screen filters in order to catch the sand as it enters the well. However, by doing so, the flow rate of heavy oil in the well can drastically fall from 7 – 15 m3/day to maybe 0.5 – 5 m3/day. On the other hand, avoidance schemes include pressure and fluid rate control, selective perforations, and resin injection to coat the sand.

As operators are following more aggressive production schedules, this has led to a demand for understanding the phenomenon of sand production mechanisms so that correct predictions of the anticipated amount of produced sand as a function of time, applied stress, and fluid flow rates can be made. The challenge is to develop a mathematical tool with a predictive capability that will allow oil operators to devise pumping schemes that produce hydrocarbons at a flow rate just below one that will produce sand.

The physics of sand production is not clearly understood. However, oil rate enhancement is often linked to solution gas effects, sand movement, and growth of large high permeability regions or cavities known as wormholes(2).
Transport of Fine Sand From a Wellbore
Authors: Mazurek K.A. , Chalaturnyk R.J. , Rajaratnam N. , Scott J.D.
Published: March 2010

This paper presents the results of an experimental study on the transport of fine sand in the entrance region of a progressing cavity pump. The study was performed to provide additional information on the behaviour of the sand slurry flow within a heavy oil well. Tests were carried out with both glycerine and water flows, with the addition of sand in the form of slugs or as a continuous feed to form a sand slurry. Several geometries of the pump intake were used. The different flow regimes observed suggest modes of operation of heavy oil wells that may be used to better avoid sanding or shutting in of wells. These results, in addition to being useful to industry, should also inspire more theoretical studies to explain the formation of the various flow features.

Introduction

The flow in a heavy oil well consists of a mixture of very viscous heavy oil, gas, water, and fine sand. For these wells, sand production can be a costly problem(1). Within the pump entrance area, there is potential for the sand to choke the flow within the well ("sanding") and production equipment. Sand may form bridges or arches within the annulus of the well to reduce flow tothe pump. Sand may also restrict flow at the intake to the pump, which can result in pump damage. It is possible that the problems associated with sand production are so costly that the well does not operate within economic limits, and is subsequently shut in or abandoned. Field monitoring of solids production in heavy oil wells typically classifies sand entrance into the wellbore to be either "continuous," where a reasonably constant value of sand is produced, or "sluggery," where slugs with high sand concentrations enter the wellbore(1).

This paper presents the results of a visualization study to investigate the mechanics of slurry flow in a heavy oil well in the area around the entrance of a progressing cavity pump(2, 3). The purpose of the study was to investigate the flow regimes created in the pump entrance area by changes in the flow rate and properties of the sand slurry fed into the well, and to assess the impact of each on sand removal in the area around the pump intake. Both a very viscous glycerine-sand slurry and a water-sand slurry were used in the experiments to examine the effect of fluid viscosity. The transport of sand was observed in a single liquid phase, with the sand added in slug form or as a continuous feed. The study also investigated the effect of the geometry of the pump intake region on sand removal from the area. Several interesting flow phenomena were observed, and are described herein.

Experimental Arrangement and Experiments

The visualization model, shown in Figure 1, examined a 1.35 m section around the pump entrance and was close in size to typical heavy oil wells in Western Canada.
Phase Equilibria Relevant to Acid Gas Injection: Part 2-Aqueous Phase Behaviour
Authors: Carroll J.J.
Published: March 2010

The purpose of this paper is to review the literature for the available experimental data and briefly survey methods for calculations of the aqueous equilibria of acid gas mixtures; notably, the water content of the gas and liquified acid gas. In addition to water, this study will include the following components: hydrogen sulfide, carbon dioxide, methane, ethane, and propane.

The design engineer should be fully informed of the capabilities of the model selected to perform the calculations. If uncertain, it is wise to verify the chosen model by comparing it with experimental data. However, as will be demonstrated, the design engineer should be critical when interpreting the available data.

Acid Gas Injection

As was stated in the first part of this paper, acid gas injection has become an important method for dealing with unwanted acid gas.

A common approach in the design of an acid gas injection scheme is to take advantage of the thermodynamics of these systems. The water content of acid gas mixture has a minimum as a function of the pressure. The design of an acid gas injection project should attempt to take advantage of this minimum, in order to eliminate the need for dehydration(1).

Water Content

An essential aspect of the design of an acid gas injection scheme is the water content of the acid gas mixture. In addition, it is important to know the effect of the state (gas or liquid) of the acid gas on the water content. Table 1 lists experimental investigations into the water content of mixtures containing hydrogen sulfide and/or carbon dioxide.

The study of Selleck et al.(2) is considered the benchmark investigation of the system hydrogen sulfide + water. They published tables of smoothed data, which are commonly quoted in the literature. However, these tables are based on relatively few and scattered experimental data points. Carroll and Mather(3) re-evaluated the phase behaviour in this system, presenting a clearer picture of the equilibria and accurately reflecting all of the available experimental data.

There have been many investigations of the water content of CO2-rich fluids. In general, there is reasonable agreement amongst the various sets of data in the low and moderate pressure regions. The benchmark investigation of the phase behaviour in the system carbon dioxide + water was that of Wiebe and Gaddy(4–6).

Finally, the author of this paper has performed thorough reviews of the literature, and is unaware of any experimental data for the water content for binary mixtures of H2S + CO2 in the public domain. Such data, if available, would be very useful.

There have been several experimental investigations into the water content of hydrocarbons. Table 2 lists those of interest in this study. In this paper, we are not strictly interested in the water content of hydrocarbons, but in acid gas mixtures containing hydrocarbons. We require a model that accurately predicts the water content of hydrocarbons in order to have the confidence that it will work for multicomponent mixtures.
3D Physical Model Studies of Downhole Catalytic Upgrading ofWolf Lake Heavy Oil Using THAI
Authors: Tare T.X. , Greaves M.
Published: March 2010

THAI-"Toe-to Heel Air Injection" is an integrated horizontal process for the recovery and in situ upgrading of heavy crude oil. In addition to thermal upgrading, further upgrading can be achieved by emplacing a catalyst layer around the horizontal producer well, in effect creating a downhole reactor. A series of six catalytic tests was performed in two 3D combustion cells to investigate the degree of upgrading achievable with 10.5 ° API gravity Wolf Lake oil. The main factors investigated were the type of HDS catalyst (NiMo, CoMo), extrudate or crushed catalyst, and catalyst loading. The results of these tests show that the basic process is very stable over a 10-hour period, maintaining an average peak combustion temperature of 500 to 600 °C. Thermal upgrading alone (THAI) achieved nearly 10 points increase in the API gravity of the produced oil. This was increased by a further 4 to 7 ° API using the catalytic process. This indicates that it may be possible to convert a heavy crude oil to almost a light oil product in a one-step in situ reservoir process. The oil recoveries were consistently very high, at around 85% OOIP, with the produced oil having a viscosity as low as 10 mPa's at 20 °C, (i.e., mPa's). The process demonstrated robust stability when changes in the air injection rate were made, and there was also an oil productivity gain when operating at a low water air ratio, WAR < 1.0.

Introduction

Unlike conventional light oil, the production of heavy oil is uch more difficult, mainly due to its high viscosity at reservoir conditions. When the oil viscosity is very high (> 10,000 mPa.s) in the reservoir, the oil is virtually immobile. Cold production of heavy oil only recovers a small proportion of the original oil in place, typically about 5% to 10%. Improved Oil Recovery (IOR) or Enhanced Oil Recovery (EOR) methods are required to increase the oil mobility and improve heavy oil production. Steam injection, vapour extraction and in situ combustion (ISC) are the three main techniques, achieving oil recoveries of more than 50% OOIP. However, expensive surface upgrading processes are required to upgrade the produced heavy oil in order to satisfy refinery feedstock specifications.

ISC is achieved by burning a small fraction of the oil in the reservoir to release the combustion reaction energy between the injected oxygen and hydrocarbons. This greatly increases the temperature in the reservoir, mobilizing the heavy oil so that it can be displaced. The high temperatures (> 500 °C) created during the in situ combustion process promote thermal cracking of the heavier components of the oil, which results in thermal upgrading. This advantage is normally not captured in the conventional ISC operation using vertical-injection and vertical-production wells (VIVP), or other conventional well patterns. This is because the thermally upgraded oil first has to bank-up in the downstream cold region before it reaches the producer well.
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

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

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

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.