bluuebunny/crossref_metadata_2025 huggingface dataset:
Residual Oil Saturation Inside the Steam Chamber During SAGD
Authors: Walls E. , Palmgren C. , Kisman K.
Published: March 2010

The oil saturation inside the steam chamber during steamassisted gravity drainage (SAGD) has an important impact on economics and conservation. However, the SAGD residual oil saturation is difficult to determine and model because it involves long-term thermal effects and three-phase flow. SAGD has been widely studied and piloted, but improved understanding of longterm drainage effects represents a fundamental issue that requires improved understanding.

In the first part of the paper, we represent a sensitivity test done on the shapes and the endpoints of the two-phase relative permeability curves. We find that the water relative permeability and oil relative permeability in the gas-oil system are the main factors that determine the magnitude and shape of the oil saturation curve as a function of time.

Secondly, we demonstrate how to adjust the krog relative permeability curve to match a theoretically determined residual oil saturation, which is supported by laboratory data. We propose that, during SAGD, the flow of oil can be split into two regimes. In the first regime, close to the edge of the steam chamber, oil drains quickly in a short period of time. In the second regime, oil drains slowly within the steam chamber for a longer period of time, as it is produced by "film drainage." To capture these flow regimes, the oil relative permeability curve in the gas-oil system, krog, is split into two. At higher liquid saturations, the first flow regime is represented and, at lower liquid saturations, the second regime is modelled.

Thirdly, the krog curve was adjusted so that the decrease in oil saturation with respect to time closely matched the theoretical curve while maintaining oil production rates expected for SAGD. Using this new curve at different pressures, we show that the residual oil saturation increases at lower SAGD operating pressures.

Introduction

In a steam-assisted gravity drainage (SAGD) process, bitumen drainage occurs mainly along the transition zone, which is the mobile liquid region at the boundary of the steam chamber. Bitumen drainage also continues to occur within the body of the steam chamber over a long period of time, such that the residual oil saturation gradually falls.

In this paper, the term residual oil saturation refers to the average remaining oil saturation within the steam chamber where the steam chamber includes all grid blocks in a numerical model containing any amount of steam. It is difficult to obtain residual oil saturation data as a function of time in the field so, in this study, we relied on theoretical and laboratory data. We calibrated reservoir simulation results to the theoretical and laboratory data, and then used the simulator to investigate the effects of SAGD operating pressures on the residual oil saturation.

Relative Permeability Formulation

Multiphase flow in a porous medium can be described using Darcy's Law as follows:
Pressure Transient Analysis for Wells With Variable Sandface Flow Rate
Authors: Nashawi I.S.
Published: March 2010

In the last two decades, with the availability of new state-of-the- art production logging devices that are capable of providing accurate downhole rate and pressure measurements, variable rate testing has been given special concern. This is mainly because it is sometimes impractical and often impossible to hold a constant flow rate long enough to perform a drawdown test. Furthermore, the use of sand face flow rate and pressure data in well test analysis has a few major advantages over conventional methods. Variable-rate tests minimize the wellbore storage effects, reduce the test duration, and provide better description of the area in the vicinity of the wellbore.

This paper presents a new technique that does not require a constant flow rate for the entire duration of the test. The technique consists of two flowing periods: a short constant flow rate period followed by a variable flow rate period. In deriving the final working equation, the variable flow rate period is approximated by a polynomial.

The new method can be also used to analyze pressure drawdown data dominated by wellbore storage and pressure buildup data pertaining to early time afterflow. Two simulated cases and two field examples are presented to illustrate the applicability of the new technique.

Introduction

The pressure drawdown test has long been recognized in the oil industry to be an excellent technique to determine reservoir characteristics. However, one of the major drawbacks in analyzing pressure draw downs is the theoretical requirement of these techniques that requires the flow rate to be held strictly constant during the entire test duration. Moreover, in most wells, the wellbore storage effects dominate the early test data and force the operator to run the test for a long period of time. This is especially true in low-productivity pumping wells and low-permeability tight reservoirs. Furthermore, in the case of small reservoirs, the boundary effects may disturb the test data even before the appearance of the semi log straight line on the test plot. Sometimes, even when the plot displays a straight line, the data analysis may not reflect the near wellbore conditions. In all of these cases, the well test fails to achieve its goals. In addition, for both oil and gas wells, the long constant-rate production condition is hard to fulfill in the field, especially during the early life of the reservoir. For all of these reasons, well test researchers tried to come up with new testing techniques that do not require a constant rate, minimize the wellbore storage effects, reflect the actual conditions in the vicinity of the wellbore, and reduce the test duration. Variable-rate tests are designed to solve most of these problems.

The idea of using afterflow data to analyze well tests is not new. As early as 1955, Gladfelter et al.(1) presented the first attempt to use approximated afterflow rate and pressure data to estimate the reservoir parameters.
Gas Exploration And Development Strategies In the Western Canada Sedimentary Basin
Authors: Flint D.W. , Dixon R.K.
Published: March 2010

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

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

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

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

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%.
Prediction of Scales in Boilers for Thermal Recovery Projects
Authors: Thimm H.F. , Kwasniewski K.
Published: March 2010

The production of silica in thermal petroleum recovery projects is a well-known phenomenon, and considerable efforts for its control are a common feature of facilities engineering in such projects. In solutions of high pH, such as boiler feedwater and blowdown, however, the silicates of iron, calcium, magnesium and sodium are of greater interest than the silica itself.

Scaling by such silicates is usually predictable by means of computer programs that rely on free energy minimizations. Where instabilities for scaling are predicted in this way, often a large range of potential mineral deposits are identified as potential scale deposits. The reality is, however, that only one or two such minerals are ever found in the analysis of pigging solids.

A simple method, that permits the prediction by non-chemists of both type and quantity of preferential scales, is derived and its use in SAGD water management and recycling schemes is illustrated. The effect of the presence of chelants in boiler feedwater may not prevent silicate scales, but merely shift the preferred scale. Sample recovery and handling, on the other hand, may cause a shift in scale preference under laboratory conditions, as opposed to facility conditions.

Introduction

The observation of scaling by metal silicates, rather than amorphous silica, is a phenomenon in SAGD operations that has been recognized relatively recently. A variety of alkaline earth silicates and mixed silicates have been observed(1,2) in various unit operations of SAGD plants, including boiler tubes, production headers and separation facilities. Analyses of fluid interactions in disposal wells also often predict formation damage due to precipitation of such silicates.

The prediction or thermodynamic confirmation of the scales found analytically is usually accomplished by water chemistry software that is based on free energy minimization. The program used in this work is the well-known SOLMINEQ program developed by the Alberta Research Council.

Silicate Scales in SAGD

A number of scales have been observed by various authors in the past few years. Table 1 provides a summary of silicate scale type and references.

The most commonly encountered scales appear to be Talc, a magnesium silicate and Tremolite, which is a more complex calcium magnesium silicate of the asbestos variety. From time to time, isomorphic substitutions are reported. Among them is Richterite, where one of the calcium atoms in Tremolite is replaced by sodium atoms.

In general, it is found that the predictive programs, when run with a given analysis, tend to predict a range of metal silicates. Given that waters in SAGD operations are generally quite soft, only one or two of the scales predicted will be found in practice, however. The purpose of this paper is to provide a simple method of predicting which of the predicted scales will be the preferred one. The importance of this work is the prediction of scale quantity. The predictive programs are able to predict a scaling index, which is not necessarily related to quantity.
Underground Gas Storage in a Partially Depleted Gas Reservoir
Authors: Soroush M. , Alizadeh N.
Published: March 2010

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

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 < υ2s> 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.
Liner Completion Difficulties Resolved With Expandable Liner Top Technology
Authors: Smith P. , Williford J.
Published: March 2010

Liner top packers, which are run as a standalone unit or integrally with conventional liner hangers, are set through the application of weight applied through the drill pipe or landing string. The capability of the liner top packer to seal at the stated pressures rated for which they are designed requires that a sufficient setting force of up to 355857.7 N (80,000 lbf) be applied through the drill pipe to the packer mechanism. Recently, work performed by an operator in Latin America showed the limitations of this process when used in shallow liner top installations where the available string weight alone to apply a sufficient setting force to the liner top packer is not available. Picking up a string of large drill collars in order to have the capability to supply the significant setting force required was an alternative. However, it was not a preferred option, safety being the main concern, followed by handling time, as was seen on the first well utilizing conventional liner hanger and liner hanger packer technology.

The expandable liner hanger (ELH) was developed as a solution to resolve the problem of weight down required to set the liner top and allowing a setting force to be applied to the packer elements locally through the hanger body with the use of hydraulic pressure. The setting force for the packer is measurable and consistent, ensuring that a liner top seal and hang weight is obtainable without requiring weight down. This system contains no moving parts, which makes it possible to function with a drill string. Once deployed in the well, the liner hanger body expands radially through the pressurization of its elastomeric elements, thus, creating a gas-tight seal and achieving zonal isolation. The operator chose to deploy the expandable liner hanger system on two subsequent wells following the initial attempt to utilize a conventional system approach. The ELH installations were successful, saving the operator several days of rig time on each well.

The case study discussion and system description presented in this paper will explain the flexibility and integrity of the expandable liner hanger in providing a liner top seal upon setting in a shallow liner top installation.

Introduction

Historically, problems obtaining a good primary cement job at the top of the liner have been associated with the installation of liners in oil and gas wells. Conventional liner hanger systems have relied upon the primary cement job to provide liner top pressure sealing integrity within the liner/casing overlap. In many wells however, cementing the complete liner and liner lap is often not achievable due to various problems, which include loss of circulation, fluid loss or other wellbore/formation conditions. In cases like these, obtaining a primary cement seal across the liner lap is not obtainable, and a liner top packer must be deployed on a second run to make the primary liner the top seal.
Cold Flow: A Multi-Well Cold Production (CHOPS) Model
Authors: Tremblay B.
Published: March 2010

A multi-well cold production (CHOPS) model, developed at the Saskatchewan Research Council, was used in conjunction with a commercial reservoir simulator, to predict the effect of well spacing and in-filling on oil recovery in cold production. The oil and sand production from the Lindbergh/Frog Lake cold production wells was history matched initially. The comparative economics of five different well spacings (10 acre, 20 acre, 40 acre, 60 acre and 80 acre) was estimated. The 20 acre spacing was the most economic overall for heavy oil prices varying between C$251/m3 (C$40/barrel) and C$502/m3 (C$80/barrel). The multi-well model was used to estimate the additional oil recovery from in-fill wells at different in-fill times. In-filling a 40 acre spacing well with 10 acre spacing wells was not economic for a Lindbergh/Frog Lake type of reservoir. In-filling the same well with 20 acre spacing wells was economic at higher oil prices in the C$502/m3 range (C$80/barrel).

Introduction

The main mechanisms which contribute to the success of the cold production process are solution gas drive and sand production. Maini(1) argued that the greater oil recovery for heavy oil compared to light oil was due to the formation of a gas in oil dispersion which he called "foamy oil." This dispersion would have a greater compressibility which would maintain the reservoir pressure for longer times. Firoozabadi(2), based on a series of solution gas drive experiments performed at reservoir-type oil velocities, attributes the greater oil recovery for heavy oil to a higher critical gas saturation and to reduced gas flow leading to reservoir pressure maintenance.

Three basic scenarios were proposed in the literature to explain how sand production leads to greater oil recovery:a limited dilated sand region around the wellbore(3),a dilated sand region around the wellbore with wormholes extending into the formation(4) andonly wormholes extending out into the formation(5, 6).

The third scenario can best explain the rapid (within a few hours) travel time of a fluorescein tracer dye between an injector and a producer, observed by Amoco in a tracer test(5). Since the concentration of this dye, which is known to adsorb on the surface of a porous medium, did not change at the producer, Squires(5) concluded that an open (sand-free) channel connected the injector and producer. This observation contradicts scenarios 1 and 2 since these scenarios preclude the existence of an open channel throughout the length of the wormholes. Field engineers have observed that they sometimes lose fluid circulation while drilling into cold produced reservoirs. The location at which fluid loss occurs can help in mapping the wormhole network in the field. For example, when Nexen Inc. drilled two horizontal wells in a field after cold production, they observed lost circulation to neighbouring wells at the locations indicated by the ? marks in Figure 1. These 40 acre spacing cold production wells had produced large quantities of sand.
Impact of Concentration-Dependence of Diffusion Coefficient on VAPEX Drainage Rates
Authors: Okazawa T.
Published: March 2010

The VAPEX analytical model is extended to cover situations when diffusion coefficients are dependent on concentration due to the extreme viscosity reduction with solvent dissolution into bitumen. The new analytical model covers such situations along with the cases in which the diffusion coefficient and viscosity relate to each other under the Stokes-Einstein law. In the process, a new concept of the 'average flow fraction of bitumen' in the flowing mixtures is introduced.

The modelled result on overall functionality of the drainage rate of bitumen has confirmed the square-root relationships to most of the key reservoir parameters as the previous theories indicate. However, its dependence to the inverse of kinematic viscosity at the interface is closer to linear rather than square-root correlation with the concentration-dependent diffusion coefficient. The theoretical relationships are confirmed by the correlations of the unified bitumen rates to kinematic viscosity at the interface using the existing VAPEX and SAGD experimental data in the literature. This finding indicates that VAPEX process in heavy oils with lower native viscosity can be more effective than originally recognized.

Introduction

Dunn et al.(1) developed the theoretical model of the gravity drainage process for bitumen recovery known as VAPEX based on the model of the steam-assisted gravity drainage (SAGD) process by Butler et al.(2) This model assumed that the diffusion coefficients of solvent-bitumen systems are constant similar to the case of thermal diffusivity. Thus, the steady-state profiles of solvent concentration ahead of the solvent-bitumen interface is the smooth exponential decay towards an infinite distance. In reality, the diffusion coefficients of both solvent and bitumen are strongly dependent upon compositions due to the extreme viscosity contrasts between the solutes and solvents. As a result, the observed concentration profiles in diffusion experiments exhibit the abrupt front-end profiles(3). The theoretical endeavour here is to understand the impact of the non-exponential concentration profiles on the VAPEX drainage and bitumen rates.

Governing Mechanisms

The most fundamental mechanism of the process is the gravity drainage caused by the density difference between the liquid-bitumen phase and the injected vapour phase. The drainage flow of the bitumen phase occurs only from viscosity reduction due to the impact of the injected solvent (or heat in the case of SAGD) of the otherwise semi-solid bitumen. Therefore, how the injected solvent penetrates into the bitumen phase in the reservoir is of primary importance to the process. According to Fick's law, a material balance across a differential distance, dx, in this situation can be expressed as a continuity equation for the change of concentration (volume fraction is chosen), C, with time, t, by using the diffusion coefficient, D:

Equations (available in full paper)
Cutting Efficiency of a Single PDC Cutter on Hard Rock
Authors: Hareland G. , Nygaard R. , Yan W. , Wise J.L.
Published: March 2010

Polycrystalline diamond compact (PDC) bits have gained wide popularity in the petroleum industry for drilling soft and moderately firm formations. However, in hard formation applications, the PDC bit still has limitations, even though recent developments in PDC cutter designs and materials steadily improves PDC bit performance. The limitations of PDC bits for drilling hard formations is an important technical obstacle that must be overcome before using the PDC bit to develop competitively priced electricity from enhanced geothermal systems, as well as deep continental gas fields. Enhanced geothermal energy is a very promising source for generating electrical energy and, therefore, there is an urgent need to further enhance PDC bit performance in hard formations.

In this paper, the cutting efficiency of the PDC bit has been analyzed based on the development of an analytical single PDC cutter force model. The cutting efficiency of a single PDC cutter is defined as the ratio of the volume removed by a cutter over the force required to remove that volume of rock. The cutting efficiency is found to be a function of the back rake angle, the depth of cut and the rock property, such as the angle of internalfriction.

The highest cutting efficiency is found to occur at specific back rake angles of the cutter based on the material properties of the rock. The cutting efficiency directly relates to the internal angle of friction of the rock being cut.

The results of this analysis can be integrated to study PDC bit performance. It can also provide a guideline to the application and design of PDC bits for specific rocks.

Introduction

PDC bits have gained popularity in drilling for petroleum due to its long bit life together with its ability to maintain a high rate of penetration (ROP). The shearing action induced by fixed cutters has shown to be more efficient for penetrating rock than the crushing effect of the teeth or inserts on the rolling cones of a roller bit(1–4). However, PDC bits have traditionally had limitations when encountering hard formations(5). Therefore, PDC bits are not yet preferred for hard formations encountered with mining, petroleum or geothermal energy. Enhanced geothermal energy, i.e., geothermal energy from considerable (+3 km) depths, is seen as one of the promising energy sources in the U.S.(6) Deep continental gas developments also suffer from a low rate of penetration and high bit wear for wells drilled.

The objective of this paper is to develop an analytical model to study the cutting efficiency of PDC bits in hard rock formations which can improve the future design of PDC bits and, thereby, improve the cost efficiency of wells in hard formations.

PDC Bit

Most PDC bits are composed of a hard matrix body which is milled out of a solid block of steel. The matrix body is milled out in such a shape that the bits contain blades where the actual PDC cutters are 'glued' or 'braced' on, and open areas where the cuttings and mud flow can escape to the annulus (Figure 1).
The Impact of Pressure Drop on SAGD Process Performance
Authors: Thorne T. , Zhao L.
Published: March 2010

Pressure drop along the horizontal wells and between the injector and producer could have a significant impact on SAGD process performance. However, this issue is poorly understood due to difficulties in simulating pressure drop. This paper presents the results of a numerical study on the topic.

When pressure drop between the injector and producer exists, the downhole vapour production rate must be increased significantly. Without adequate vapour production, the oil production rate is lower and SOR is higher. Increasing the vapour production rate may affect pad facility design as more vapour handling capacity is required under these conditions.

On the other hand, pressure drop inside the injection well may also alter steam distribution. However, the impact on oil production is limited as steam can move relatively easily inside the steam chamber. In the present case, oil production is reduced by approximately 5% when a pressure gradient along the injection well is considered.

Introduction

Steam-Assisted Gravity Drainage (SAGD), a thermal process that involves the application of steam and the use of horizontal wells, is a bitumen recovery method used in the Athabasca Oil Sands. The most common implementation involves the use of two horizontal wells drilled parallel to one another with a vertical separation distance of about 5 m. The upper well is known as the injector and the lower well is known as the producer.

Through the operation of commercial projects, it has been observed that once steam is injected into the reservoir, a pressure gradient is observed along and between the wells. There have been a number of publications addressing this issue(1, 2).

As the SAGD process has been applied to more locations in recent years, considerable interest has been generated around the topic of pressure drop and its effect on SAGD process performance. It is generally understood that a pressure drop across or along the wellbore could result in wells with a non-uniform steam chamber, a reduced effective wellbore length, liquid build-up above the production well or reduced oil production rate.*

When a new reservoir is developed, a great effort is required to understand the reservoir characteristics and how to incorporate them into production forecasting models. Petro-Canada is currently expanding their MacKay River project and, in order to develop a better understanding between pressure drop and oil productivity, the field data from their existing project was analyzed so that recommendations could be made to increase the project's productivity.

One factor that needs to be addressed for drilling and completion planning is the wellbore size. Larger wellbore size results in more uniform steam distribution in the injection well and increased productivity from the production well. However, a larger wellbore size incurs a higher cost.

In some existing wells, it was found that liquid build-up was occurring due to limited lifting capacity. In addition, a larger pressure drop between the injector and the producer has been observed.