Role of Asphaltene Precipitation in VAPEX Process

Abstract

VAPEX (vapour extraction) is an oil recovery process, in which heavy oil or bitumen is mobilized by injection of a low molecular weight hydrocarbon solvent and is drained by gravity to a horizontal production well. It has attracted considerable attention because of its potential applicability to problematic reservoirs and the potential for in-situ upgrading of heavy oil during the process.

Oil drainage rate under VAPEX is controlled by the viscosity of solvent diluted oil and can be affected substantially by de-asphalting. In-situ de-asphalting can be advantageous because it reduces the oil viscosity and leads to production of upgraded oil. However, the precipitated asphaltenes can also plug the pores of the formation and cause severe damage to the permeability.

The objective of the current work was to determine whether the beneficial effects of asphaltene precipitation would outweigh any formation damage. The effects of in-situ precipitation and deposition of asphaltenes on the rate of oil drainage and the quality of the produced oil under different operating conditions were experimentally evaluated. The experiments were conducted in a physical model, packed with 140 - 200 mesh sand, and propane was used as the solvent. The quality of the produced oil samples was evaluated through the SARA technique and viscosity measurements.

The experimental results show that the oil produced at higher injection pressures was substantially upgraded, but the viscosity reduction by asphaltene precipitation did not lead to higher production rates. The effect of viscosity reduction was negated by the accompanying damage to formation permeability. The huff and puff injection of toluene into the production well, to remove damage from the near well zone, was tried but proved to be ineffective. It led to production of oil with higher asphaltene content with no improvement in the rate of oil production compared to the lower pressure operation without asphaltene precipitation. However, co-injection of toluene with propane was successful in increasing the rate of production and the extent of upgrading obtained was encouraging.

Measurements and Modelling of Phase Behaviour and Viscosity of a Heavy Oil/Butane System

Abstract

Solvent-based heavy oil recovery methods are of interest as environmentally friendly alternatives for thermal techniques. The phase behaviour data from a heavy oil/solvent system are important information required for feasibility studies and numerical simulation of such processes. The scarcity of experimental data in the literature is a challenge in modelling of solvent involving processes. The variety of the solvent/oil mixtures, which are being evaluated within ongoing researches such as the VAPEX (vapour extraction of heavy oil) process, requires accurate description of the system's pressure, volume and temperature (PVT) properties.

In this study, an experimental setup was designed to perform a series of PVT experiments and viscosity measurements. The results of the PVT tests conducted with the Frog Lake heavy oil and butane as a solvent are presented. The same oil/solvent pair was used in the VAPEX experiments previously reported by the authors(1, 2). The measurements include the solvent solubility in the oil, mixture density and mixture viscosity at different saturation pressures.

To simulate the phase behaviour of the system, an equation of state (EOS) was tuned using the measured experimental data and a phase behaviour package (WINPROP). The predicted densities and saturation pressures by the EOS are in very good agreement with the experimental data. A mixing viscosity correlation was also tuned with the measured data and found to be representative for describing the viscosity of the system. The viscosity data were compared with the predictions of several other available correlations, and it was shown that Shu's model(3) reproduces acceptable data for reservoir simulation purposes.

Introduction

Solvent-involving recovery processes have recently gained some attention. These processes often involve relatively light hydrocarbon solvents such as C3 - C7, which are sometimes co-injected with non-condensable gases such as CO2, CH4 and N2. Numerical simulation studies of such processes are, however, in early stages to investigate the feasibility of field implementation, improvement and optimization. Numerical modelling of these processes is mostly performed on compositional simulators to capture the potential compositional changes, asphaltene precipitation and diffusion/dispersion mechanisms. Phase behaviour of the heavy oil/solvent system is one of the most vital pieces of input data that can be predicted and produced by either a series of k values or a tuned EOS. Nonetheless, both methods rely on accurate experimental phase behaviour information.

Steam Flooding of Naturally Fractured Reservoirs: Basic Concepts and Recovery Mechanisms

Abstract

A review of important issues in steam injection in naturally fractured reservoirs (NFRs) is presented. The effect of temperature on physical properties of crude oils and rocks and the thermo-chemical alteration of crude oil are discussed.

The recovery of oil from NFRs can be modelled as a two step process: first the oil is expelled from the matrix blocks through mechanisms that impose a pressure gradient within each matrix block and then it is swept through the fracture network to a production well by mechanisms that impose a pressure gradient within the fracture network. The recovery mechanisms associated with steam injection in NFRs and their characteristic times are presented. The most important recovery mechanism in matrix blocks is differential thermal expansion between oil and the matrix pore volume and the strongest mechanism in fracture network is the reduction of viscosity ratio (µo/µw). The matrix oil recovery mechanisms are relatively independent of oil gravity, making steam an equally attractive recovery process in fractured light and heavy oil reservoirs.

The mechanism and impact of CO2 generation during steam injection in carbonate reservoirs are discussed. The rate of CO2 generation is controlled by the rate of heat conduction from fracture into the matrix. For a specific reservoir the rate of heat conduction is a function of temperature and injection rate of steam and these can be optimized to make use of the in situ generated CO2.

Introduction

Heavy oil in naturally fractured carbonate reservoirs is an important resource, which accounts for one-third of total heavy oil worldwide. Many fractured reservoirs in the Middle East, former Soviet Union and Canada are candidates for thermal heavy oil recovery. Steam injection processes, which have been used extensively to recover heavy oil from non-fractured reservoirs, were not applied to fractured reservoirs until recently. This was primarily based on the belief that the injected steam would bypass the oil through the fractures and would be ineffective in recovering the oil. However, the results of experimental, theoretical and pilot tests which have appeared in the literature since early 1980s, show the feasibility of heavy oil recovery from fractured reservoirs using steam injection.

Phase Behaviour and Physical Property Measurements for VAPEX Solvents: Part II. Propane, Carbon Dioxide and Athabasca Bitumen

Abstract

The solubility of pure carbon dioxide in Athabasca bitumen was measured and compared with the literature data. Multiple liquid phases were observed at carbon dioxide contents above approximately 12 wt%. A correlation based on Henry's law was found to fit the saturation pressures at carbon dioxide contents below 12 wt%.

The saturation pressure and solubility of carbon dioxide and propane in Athabasca bitumen, as well as the liquid phase densities and viscosities, were measured for three ternary mixtures at temperatures from 10 to 25 °C. Two liquid phases (carbon dioxide-rich and bitumen-rich) were observed at 13 wt% carbon dioxide and 19 wt% propane. Only liquid and vapour-liquid regions were observed for the other two mixtures (13.5 wt% propane and 11.0 wt% carbon dioxide; 24.0 wt% propane and 6.2 wt% carbon dioxide). The saturation pressures for the latter mixtures were predicted using the correlation for the carbon dioxide partial pressure and a previously developed correlation for the propane partial pressure. The mixture viscosities were predicted with the Lobe mixing rule.

Introduction

In Part I of this work(1), mixtures of carbon dioxide and propane were identified as a potential solvent for the VAPEX process. At typical heavy oil reservoir conditions (pressure of ~1.2 MPa and temperature of ~10 °C), propane and butane have sufficient solubility to reduce the oil viscosity to a level where gravity drainage can occur in an economic time scale. However, propane and butane are expensive solvents and the success of the process depends on how much solvent can be recovered. As well, the VAPEX process operates below the saturation pressure of the solvent and, therefore, propane and butane cannot be used at higher reservoir pressures where they exist only in the liquid phase. Methane can be added to achieve the desired pressures(2). However, carbon dioxide may also be a better VAPEX solvent than methane because it is more soluble in heavy oil and significantly reduces the viscosity(3). Mixtures of carbon dioxide and propane may achieve the desired reduction in viscosity while minimizing the required propane volumes. Hence, there is an incentive to evaluate mixtures of carbon dioxide and propane as a VAPEX solvent.

VAPEX performance depends on the viscosity and density of the liquid phase that forms at the edge of the vapour chamber. In order to design and optimize VAPEX and other solvent-based processes, it is critical to be able to determine the diffusivity of the solvent in the heavy oil, identify the phases that form in the solvent and heavy oil mixtures at various temperatures and pressures, and determine the density and viscosity of the liquid phase. Other solvent-based processes (steam and solvent injection for heavy oil recovery and solvent extraction of oil sands) require similar data.

In Part I of this work(1), saturation pressures and liquid phase densities and viscosities were measured for propane and Athabasca bitumen. There are also considerable data in the literature for mixtures of carbon dioxide and crude oils. Simon and Graue(4) measured the solubility, swelling and viscosity of mixtures of carbon dioxide and nine different oils.

Experimental Investigation of CO-Based VAPEX for Recovery of Heavy Oils and Bitumen

Abstract

Vapour extraction (VAPEX) has recently emerged as an attractive alternative to thermal recovery techniques for the huge resources of heavy oils and bitumen available in Canada, the USA and Venezuela. The current version of VAPEX relies on the injection of light hydrocarbon gases for reducing the oil viscosity. The economic viability of this process is very sensitive to the cost of injected gases in relation to the selling price of the produced oil. One attractive option for reducing the cost of injected gases appears to be the use of CO2 as a major component of the injected solvent. This modification will utilize mixtures of CO2 and propane as the solvent instead of the currently popular mixtures of methane and propane. Since CO2 is significantly more soluble in heavy oils than methane, it is likely that such mixtures will provide greater reduction in viscosity compared to equivalent mixtures of methane and propane.

In this work, methane-propane and CO2-propane were investigated as solvents for the VAPEX process for in situ recovery of heavy oil and bitumen. Twelve laboratory experiments were performed with two types of oil [4,500 mPas and 18,600 mPas at 294.15 K (21 ºC)]. These tests were performed in a partially-scaled physical model at different operating pressures ranging from 1,469.3 kPa (200 psig) to 4,227.2 kPa (600 psig) and were designed to compare the performance of methane-based solvents with that of CO2-based solvents. The main conclusion from this study is that the CO2-based VAPEX process can be more cost effective and environmentally friendly than the conventional VAPEX process.

Introduction

With the decline of conventional oil reserves, a major thrust of oil producers throughout the world is on the exploitation of heavy oil and bitumen reserves. The magnitude of these resources worldwide is about six trillion barrels of oil-in-place; six times total conventional reserves(1), and is likely to be the future source of energy. The majority of these resources are located in Venezuela, Canada and the United States(2). In most cases, conventional recovery methods cannot be implemented in heavy oil and bitumen reservoirs due to the high viscosity(3) of the oil. The high viscosity rules out primary production in many reservoirs, and even in lower viscosity reservoirs, the primary recovery is less than 10% of the original oil-in-place (OOIP)(4, 5).

The Steam-Assisted Gravity Drainage (SAGD)(6, 7) process has gained tremendous popularity in the industry for its usefulness in producing high viscosity heavy oil and bitumen. In this process, the heat is injected into the reservoir by injecting steam through a horizontal well; steam condenses at the boundary of a growing steam saturated zone and heats the oil. Consequently, the viscosity is lowered and the hot oil drains down under the influence of gravity into another horizontal well located near the bottom of the formation. Even though thermal methods are successful in exploiting these resources, they often suffer from low energy efficiency due partly to heat losses to the cap and base rock.

Fluid Movement in the SAGD Process: A Review of the Dover Project

Abstract

The fundamentals of Steam Assisted Gravity Drainage (SAGD) steam chamber development are now well understood through Butler's analytical models, as well as extensive field and laboratory testing. However, as the industry continues to extend SAGD to new reservoirs and look towards SAGD wind-down at the end life of projects, it is important that we recognize the value of not only understanding the steam chamber, but also of the movement of fluid in the reservoir. The Dover SAGD Pilot is the most mature pilot of its kind in the world. A study of this project has been undertaken in an attempt to understand the behaviour of the fluid within and in front of the steam chamber.

The economics of SAGD are significantly impacted by the cost of generating steam. At roughly 283.17 m3/bbl (1 mcf/bbl) of bitumen produced for a steam-oil ratio (SOR) in the range of 2.3 to 2.5 m3/m3, natural gas is the single largest operating cost in a SAGD project. Water movement within the reservoir can impact the natural gas consumption, whereas warm steam condensate not reproduced must be replaced in the process by colder make-up water decreasing the heat efficiency of the steam generation. Further, where water loss to the reservoir is high, the SOR may be negatively impacted. On the 20th anniversary of the initiation of the Dover Pilot, the cold water injection test performed prior to any thermal operations taking place is revisited here. Understanding the transmissibility of water in the reservoir is key to choosing the optimal operating pressures and maximizing the value of a project.

It has been widely published(1,2) that the injection of non-condensable gas (NCG) into SAGD chambers will result in the accumulation of the NCG at the top of the chamber, cooling the chamber. The lower temperatures within the chamber cause the viscosity of the bitumen to increase, thereby reducing the bitumen production rate. This has been suggested as a method of winding down steam chambers as they reach their economic producing limits(3–5). From April 1998 to May 2002, NGC was injected with steam at the Dover Pilot. The gas volume injected was triple the volume of the produced bitumen over that time. The SAGD chambers did not behave as predicted. The bitumen production rate did not fall off any more than would be expected from a mature steam chamber and live steam was still detectable through the thermocouples within the steam chamber. Furthermore, an increased overall recovery was observed, most likely from gas assistance in the production of previously inaccessible reserves. The simulation model developed to describe the behaviour of NCG in the reservoir, as well as further observations regarding this behaviour, are discussed.

Introduction

Geographically located in northeast Alberta, the Athabasca oil sands deposit forms part of the Western Canadian oil sands. With an estimated 1.7 trillion barrels of oil-in-place, it is arguably the single largest oil deposit in the world. SAGD, developed by Butler in the early 1980s(6) is, to date, the most successful in situ method of exploiting this resource.

Temperature Effects From the Conditioning and Flotation of Bitumen From Oil Sands in Terms of Oil Recovery and Physical Properties

Abstract

Batch extraction tests show that, for Athabasca oil sands, the water-based conditioning/flotation process can be adjusted from 80 to 50 ° C conditions without substantial changes in optimal process aid addition level or primary oil recovery obtained. When the process temperature is further reduced to 25 ° C however, an order of magnitude reduction in primary oil recovery is obtained, suggesting that one or more key process variables have undergone a substantial change. Our studies with process additives suggest that several key physical properties undergo major changes, including bitumen viscosity, interfacial tension, and interfacial charge. If these are addressed, then comparable optimum primary oil recoveries can be achieved under all of 25, 50, or 80 ° C conditions. This is a significant result in terms of identifying the key mechanism(s) by which good primary froth recovery can be achieved. It is shown that the interfacial property changes, in particular, are consistent with the expected thermodynamic conditions necessary for efficient bitumen separation and flotation.

Introduction

Oil sands are unconsolidated sandstone deposits containing bitumen, which is chemically similar to conventional crude oil, but has a greater density (a lower API gravity) and a much greater viscosity. Because sediments were brought in to the Athabasca deposit area from different sources and at different times, the oil sands occur as a mixture of sediment types, overlain by varying thicknesses of non-oil bearing formations(1, 2), so that a diverse number of distinct depositions can be discerned(2–5). Accordingly, the oil bearing sands have great variability in their compositions and properties and while in oil sand processing the general principles of mineral flotation apply, oil sand composition and structure, and their variations, have a great impact on the way the flotation must be operated.

The hot water flotation process for oil sands is a separation process in which the objective is to separate bitumen from mineral particles by exploiting the differences in their surface properties. The slurry conditioning process involves many process elements, including ablation, mixing, mass and heat transfer, and chemical reactions leading to the separating of bitumen from the sand and mineral particles. Adopting the water-wet model for Athabasca oil sand, one assumes that a thin aqueous film already separates the bitumen from the sand; this separation needs to be enhanced. Disengagement of bitumen from solids will thus be favoured if their respective surfaces can be made more hydrophilic, since a lowering of surface free energy will accompany the separation. The phase separation is enhanced by the effects of mechanical shear and disjoining pressure.

Although there are many variables, including water addition ratios, mechanical energy input levels, chemical addition levels, temperatures, and residence times, process efficiency is more sensitive to some variables than to others(6, 7). Early studies led to the identification of base (NaOH) addition level as the preferred process variable [see the review in Reference (8)] and it was shown by Sanford(9) that NaOH addition level could be controlled in response to fines level in the feed.

The Role of Diffusion and Convective Dispersion in Vapour Extraction Process

Abstract

Vapour extraction (VAPEX) is a potentially economic process for the recovery of heavy oil and bitumen in Canadian reservoirs, as all of the injected solvent is effectively delivered to the zone of interest. In addition, the process has the potential to sequester greenhouse gases, and is capable of in situ upgrading of heavy oil.

The research described in this paper was undertaken to identify the main processes governing the interfacial mass transfer of solvent into bitumen. A number of experiments were carried out in a Hele-Shaw cell, and the results were incorporated into a predictive model. Good agreement between theory and experiment was found when dispersion effects were incorporated into a mass transfer model of the process at identical values of Peclet number.

Introduction

Vapour extraction (VAPEX) is an alternative method for recovery of heavy oil and bitumen. This technique, which involves a solvent-leaching gravity drainage mechanism, reduces the viscosity of heavy oil by dissolution of a vapourized solvent into the bitumen.

VAPEX has recently received a lot of attention from industry, as a promising means for recovery of heavy oil deposits in Canada. The primary drive for this interest is the potential economic attractiveness of the process in comparison to other heavy oil recovery techniques. Unlike steam injection, which is associated with significant heat losses to the media surrounding the wellbore and reservoir, all of the injected solvent by VAPEX is effectively delivered to the zone of interest. This process also appears to provide an alternative method for potential sequestration of greenhouse gases, particularly in regions at close proximity to power plants of northern Alberta. Moreover, experimental work has proved that VAPEX is capable of in situ upgrading of the heavy oil, due to the stripping phenomenon associated with scavenging the lighter end hydrocarbons by the flowing solvent(1).

Therefore the costs associated with treatment and processing of produced oil by VAPEX is considerably less than that for other heavy oil production schemes.

The prime objective of this paper is to identify the main processes governing the interfacial mass transfer of solvent into bitumen and incorporate those mechanisms into a reliable, predictive model. The estimated recovery rates for laboratory experiments in a Hele-Shaw cell appears to be well within the range of drainage rates predicted by molecular diffusion-based models(1). However, subsequent experiments in sand-packed porous media resulted in drainage rates, considerably higher than predicted values from analytical models(1, 3-5).

Earlier researchers had suggested several different factors that might potentially enhance the mass transfer of solvent into the bitumen in the VAPEX process(5). However, no systematic investigation was carried out to understand and/or verify the viability of either of their proposed enhancement mechanisms.

In order to have a better understanding of the dispersion and diffusion mechanisms of mass transfer for VAPEX, we began our experiments in a Hele-Shaw cell. Further experiments will be conducted in porous media, once the questions surrounding the process in a Hele-Shaw cell are addressed.

Echocardiography in patients with suspected endocarditis: a cost-effectiveness analysis

PURPOSE

We sought to determine the appropriate use of echocardiography for patients with suspected endocarditis.

PATIENTS AND METHODS

We constructed a decision tree and Markov model using published data to simulate the outcomes and costs of care for patients with suspected endocarditis.

RESULTS

Transesophageal imaging was optimal for patients who had a prior probability of endocarditis that is observed commonly in clinical practice (4% to 60%). In our base-case analysis (a 45-year-old man with a prior probability of endocarditis of 20%), use of transesophageal imaging improved quality-adjusted life expectancy (QALYs) by 9 days and reduced costs by $18 per person compared with the use of transthoracic echocardiography. Sequential test strategies that reserved the use of transesophageal echocardiography for patients who had an inadequate transthoracic study provided similar QALYs compared with the use of transesophageal echocardiography alone, but cost $230 to $250 more. For patients with prior probabilities of endocarditis greater than 60%, the optimal strategy is to treat for endocarditis without reliance on echocardiography for diagnosis. Patients with a prior probability of less than 2% should receive treatment for bacteremia without imaging. Transthoracic imaging was optimal for only a narrow range of prior probabilities (2% or 3%) of endocarditis.

CONCLUSION

The appropriate use of echocardiography depends on the prior probability of endocarditis. For patients whose prior probability of endocarditis is 4% to 60%, initial use of transesophageal echocardiography provides the greatest quality-adjusted survival at a cost that is within the range for commonly accepted health interventions.

A Non-equilibrium Model to Calculate Foamy Oil Properties

Abstract

A number of heavy oil reservoirs under solution gas drive show anomalously good primary performance. Foamy oil behaviour is believed to be one of the reasons. Several previous investigators have developed numerical models to simulate the foamy oil flow. These models account for the presence of foamy oil effects by modifying the equilibrium properties of the rock-fluid system, such as the PVT characteristics and relative permeability. Their approach does not account for the time (or rate) dependent changes in foamy oil characteristics. This paper proposes a methodology for including the non-equilibrium processes in calculating the foamy oil properties.

The basic foundation of this model rests on theories of bubble nucleation and bubble growth. However, several simplifying assumptions have been used to keep the mathematical treatment tractable and to maintain consistency with reported experimental observations. The model is verified by matching our calculated results with the experimental data.

The results calculated from this model show how the foamy oil properties vary with pressure and time. The volumes and compressibilities of foamy oil increase to their maximum values before they decrease with time. The maximum values strongly depend on the amount of the gas that can be entrained in the liquid oleic phase. The amount of entrained gas is a key parameter in foamy oil flow.

This method of calculating foamy oil properties provides the basics for developing numerical simulation models of foamy oil flow. The results from this model may also be useful for well testing analysis in foamy oil reservoirs.

Introduction

A number of heavy oil reservoirs under solution gas drive show anomalously good primary performance: high oil production rates, low produced GOR and high recovery(1, 2). These reservoirs show "foamy-oil" behaviour in wellhead samples produced under solution gas drive. The oil is produced in the form of an oil-continuous foam which has the appearance of chocolate mousse and contains a high volume fraction of gas(3).

Foamy oil may be defined as a heavy oil containing dispersed gas bubbles(4). In the context of solution gas drive, its physical form could be a dispersion of gas bubbles flowing with the oil; a foam in which the continuous phase is oil; or any other form which causes trapping of a large volume of gas within porous media. Foamy oil flow was defined by Maini(5) as an unusual form of two-phase (oil/gas) flow in porous media which can be invoked to explain the high solution-gas-drive recovery in some heavy oil reservoirs. To study the foamy oil flow, it is important to first understand the foamy oil properties. The most important properties related to flow are the compressibility and viscosity.

The compressibility of a foamy oil (oil containing dispersed gas bubbles) would obviously be much higher than the compressibility of the same oil containing only dissolved gas. Since the gas compressibility is much higher than the liquid compressibility, the total compressibility of the dispersion would be dominated by the gas, once a significant volume fraction of gas has evolved.

Evaluation of Emulsified Solvent Flooding For Heavy Oil Recovery

Abstract

Efficient secondary and tertiary recovery of heavy oil from thin reservoirs, such as those in the Lloydminster area, remains an unsolved challenge to IOR researchers. The primary recovery from these heavy oil reservoirs is generally poor (often less than 5% of original oil in place) and waterflooding is rather inefficient due to very adverse mobility ratio which results in severe viscous fingering and early water breakthrough. Thermal methods are also not viable due to excessive heat losses to the underlying and overlying formations. Non-thermal techniques involving injection of a miscible solvent are uneconomical due to the high cost of solvent in relation to the market value of the heavy oil recovered. Therefore, there is a need for novel processes designed specifically for such reservoirs.

This paper presents an experimental evaluation of the use of emulsified solvents to recover heavy oil from thin reservoirs. The emulsified solvent flooding can potentially provide the high recovery efficiency of miscible solvents at a fraction of the cost. The process, if successful, would have wide application in thin heavy oil reservoirs.

Commercially available emulsifiers were used to formulate solvent-in-water emulsions using natural gas condensate or petroleum naphtha as the solvent. The oil recovery potential of these emulsions was evaluated in one metre long linear sandpacks and in a three-dimensional glass-bead packed visual model. Effects of various process variables, including: solvent volume fraction; surfactant concentration; flow velocity; and oil viscosity, on oil recovery performance were experimentally evaluated.

The results show that the emulsified solvent flooding provides significantly superior displacement efficiency compared to straight solvent injection and waterflooding. The mechanisms responsible for such high efficiency include:reduction in oil viscosity due to dilution by the solvent;mobility control provided by the trapping of emulsion droplets at pore throats; andin situ emulsification of the oil being displaced. The relative importance of these mechanisms was evaluated under different conditions.

An economic analysis showed that, although the process can recover a large fraction of the oil in place, it would not be profitable under current price conditions. Several novel ideas for improving the performance are suggested.

Introduction

Vast reserves of heavy oil which can be mobilized at reservoir conditions exist in the Lloydminster area of east central Alberta and west central Saskatchewan. Although the oil in these reservoirs is mobile, its production is hampered by high viscosity and the primary recovery is typically between 5 – 10%. Enhanced recovery by steam injection is generally not profitable in these relatively thin reservoirs because of the excessive heat losses to the surrounding rock formations. Non-thermal techniques involving injection of a miscible solvent are also uneconomical due to the high cost of solvent in relation to the market value of the heavy oil recovered. Therefore, new recovery processes are needed to economically recover the heavy oil from these reservoirs.

One attractive alternative to miscible solvent injection appears to be the Emulsified Solvent Flooding process. It has the potential to provide the high displacement efficiency of a miscible flood ata significantly lower cost due to the reduced solvent requirements.

Gastric intramucosal pH changes after volume replacement with hydroxyethyl starch or crystalloid in patients undergoing elective abdominal aortic aneurysm repair

PURPOSE

Gastric intramucosal pH (pHi), a surrogate marker of tissue oxygenation, falls following abdominal aorta aneurysm (AAA) repair. We tested the hypothesis that volume replacement with a hydroxyethyl starch solution would result in better preserved splanchnic oxygenation than would volume replacement with crystalloid solutions.

MATERIALS AND METHODS

This was a prospective, randomized, nonblinded study set in a university-affiliated community hospital. Thirty patients undergoing elective AAA repair were studied. Patients were randomly selected to receive intraoperative and postoperative fluid replacement with either hetastarch or crystalloid. According to the study protocol, patients could not receive in excess of 3,000 mL of hetastarch. Tissue oxygenation was assessed indirectly by measuring pHi using a nasogastric tonometer. Hemodynamic, oxygenation, and pHi data were collected preoperatively, preclamp, before unclamping, at the end of the procedure and postoperatively for 24 hours. Coagulation parameters were determined preoperatively and postoperatively for 24 hours.

RESULTS

Fifteen patients were randomized to each group. There were 18 male and 12 female patients, whose mean age was 66 +/- 9 years. The intraoperative fluid balance was significantly greater in the crystalloid compared with the hetastarch group (4,194 +/- 1,500 mL v 2,949 +/- 1,123 mL; P = .05, 95% confidence interval [C] 23 to 2,519 mL). There were no significant differences in the amount of intraoperative blood loss or postoperative transfusion requirements between the two groups. The difference between the preoperative pHi and nadir was 0.07 +/- 0.03 in the hetastarch group compared with 0.13 +/- 0.04 in the crystalloid group (P = .001, Cl 0.03 to 0.09). By multivariate analysis the only variable that influenced the fall in pHi was the type of resuscitation fluid (F ratio of 7.63; P = .01). There were no significant differences in hemodynamic- and oxygenation-derived variables or coagulation parameters between the two groups of patients. The length of mechanical ventilation, intensive care unit, and hospital stay was comparable between the two groups of patients.

CONCLUSION

In patients undergoing major surgery, volume resuscitation with hydroxyethyl starch solutions may improve microvascular blood flow and tissue oxygenation.

The incidence of deep venous thrombosis in ICU patients

STUDY OBJECTIVE

To determine the incidence, clinical presentation, and risk factors of deep venous thrombosis (DVT) in a high-risk group of ICU patients receiving DVT prophylaxis.

DESIGN

A prospective cohort study.

SETTING

Two ICUs of a university-affiliated teaching hospital.

PATIENTS

Patients admitted to the ICUs within 48 h of hospitalization and who had an ICU stay of > or = 4 days underwent venous duplex scans.

INTERVENTIONS

None.

RESULTS

One hundred two patients were studied. Ninety-four (92%) patients received DVT prophylaxis. Twelve patients (12%) were documented to have DVT by venous duplex scans. There was proximal clot extension in eight of these patients, four of whom had high-probability ventilation/perfusion scans. Of the 56 patients without signs or symptoms of DVT, only two (3.6%) had abnormal scans. Leg swelling was present in 11 patients, six of whom had DVT (p = 0.004). One of 11 patients with unexplained fever had an abnormal scan. Five of the 26 patients (19%) receiving pneumatic compression developed DVT compared with five of 68 patients (7.4%) receiving subcutaneous heparin (not significant). No specific factor was identified that increased the risk of DVT.

CONCLUSION

In this study, the incidence of DVT in a group of high-risk ICU patients receiving DVT prophylaxis was 12%. Since scans in patients without signs or symptoms suggestive of DVT were abnormal in only 3.6% of patients, venous scans should be performed only in patients with features suggestive of DVT or pulmonary embolism.

Effects Of Temperature On Heavy Oil-Water Relative Permeability Of Sand

Abstract

Although a number of studies have reported significant effects of temperature on relative permeabilities no consensus has emerged on the generality of such effects nor on possible mechanisms causing such effects. Some of the recent studies have found relative permeability to be independent of temperature and have suggested that most of the reported temperature effects can be attributed to artifacts of the unsteady-state technique. The objective of this study was to critically examine the use of the unsteady-state technique for measuring relative permeability in heavy oil systems and to experimentally determine the effect of temperature on relative permeability curves for a clean silica sand/heavy crude oil/deionized water system.

Unsteady-state measurements were carried out in a 45 cm long, 5.6 cm diameter sand core at five different temperatures ranging from room temperature to 200 °C using a heavy crude oil and deionized water. It was found that the unsteady-state technique when employed in heavy oil systems is more susceptible to experimental artifacts (compared to its use in light oil systems), however, a careful analysis of the displacement data can provide meaningful relative permeability curves in spite of the inevitable artifacts.

The relative permeability curves derived from production and pressure drop histories of the displacements at different temperatures showed that, in this system, relative permeability curves vary with temperature. The endpoint water permeability as well as the effective water permeability at intermediate saturations increased with increasing temperatures. The endpoint oil permeability was found to be independent of temperature. While the shape of the oil relative permeability curve displayed a complex dependence on temperature, its significance remains uncertain due to the presence of several artifacts.

Introduction

Production of oil from petroleum reservoirs usually involves simultaneous flow of two or more immiscible fluids through a porous rock. Multiphase flow in porous media is a complex process that depends on a number of factors including the absolute permeability, pressure drop, capillary pressure, fluid viscosities, and relative permeabilities of each phase. Of these, the relative permeability is probably the most important parameter in determining reservoir performance. For modelling thermal recovery processes for heavy oil recovery, one needs to know not only the relative permeabilities at the original reservoir conditions but also the effect of increasing temperature on the relative permeability curves.

A number of studies have discussed the temperature effects on oil/water relative permeabilities. Unfortunately, no consensus has emerged on the generality of reported temperature effects nor on possible mechanisms causing such effects. A brief summary of the recent literature on the effect of temperature on relative permeability is presented in Table 1. Three out of the nine experimental studies listed in this table show relative permeability to be independent of temperature while the other six report significant temperature effects. Most of the studies that report significant temperature effects suggest that irreducible water saturation increases and residual oil saturation decreases with increasing temperature.

There is obvious disagreement among researchers on the existence of temperature effects and this disagreement appears to be independent of which measurement technique was employed or whether or not crude oil was used in the tests.

Laboratory Evaluation Of Foaming Agents For High-Temperature Applications — I. Measurements Of Foam Stability At Elevated Temperatures And Pressures

Abstract

Use of foaming agents holds considerable promise for mitigating the detrimental effects of gravity segregation and viscous fingering in steam drives. Field application of such foams requires careful selection of the foaming agent and judicious design of the injection scheme. In view of the large number of foaming agents commercially available, most of which have never been field tested, the task of selecting the most suitable chemical often requires extensive laboratory evaluations. Measurements of foam stability at steam temperature can be used as the first screening test for selecting foaming agents.

This paper presents the results of experimental evaluation of foam stability under conditions of high pressure and elevated temperatures. Foaming agents were tested at different pressures (up to 6.9 MPa) and temperatures up to 200 °C. Foams were generated by injecting nitrogen gas through a gas sparger submerged under the test solution in pressure vessels equipped with glass windows. The drainage of liquid from the foam as well as the rate of decay of the foam volume were then monitored.

Results show that the drainage of liquid from foam generally follows first-order kinetics, while the decay of foam volume can be more complex. The half-life for foam volume decay declined dramatically with increasing temperature. At the highest temperature investigated, sulphonates were found to be clearly superior. The relative performance of long-chain alpha olefin sulphonates improved with increasing temperature. This suggests that, at higher temperatures, chain lengths longer than those presently available might be advantageous.

Introduction

Gravity segregation and viscous fingering are detrimental to the efficiency of many enhanced oil recovery techniques. This is particularly true for recovery of heavy oils with steam drive due to the extremely adverse mobility ratio and the wide difference between densities of steam and reservoir fluids. It has been known for more than 25 years(1) that the efficiency of miscible and immiscible gas drives can be improved by generating a foam which is considerably less mobile compared to the gas.

In the case of steam drive, it has been postulated that, if steam is injected as part of the gas phase in a foam, it will partially plug oil-depleted zones and high-permeability channels(2,3). This would divert steam toward undepleted zones and thereby improve oil recovery.

Although the steam foam process is conceptually simple, its application on a field scale is not straightforward. It requires careful evaluation of the potential benefits in relation to the cost of the injected chemicals. For best performance, the foaming agent should possess a number of desirable characteristics. These include the capacity to generate a stable foam at steam temperature and high pressure, thermal stability, low adsorption on rock surfaces, compatibility with reservoir fluids, high apparent viscosity of produced foam in porous media, and low cost. Presently, no foaming agent is known to satisfy all these requirements. Laboratory evaluations are therefore required to select the most suitable chemical for a given application.

Most of the reported screening studies for identifying promising foams have employed some form of foam stability measurement for initial screening.

Retention Of Foam-Forming Surfactants At Elevated Temperatures

Abstract

There is considerable interest in the use of foam-forming surfactants for mobility control in steamfloods. To provide effective mobility control, the injected surfactant must propagate from the injection well toward the production well. One of the important parameters affecting foam propagation through the reservoir is the retention of surfactant due to its adsorption on reservoir rock. Because the foam encounters a range of temperatures and salinities between the injection and production wells, it is necessary to evaluate the temperature and salinity dependence of surfactant adsorption.

This paper reports on the results of adsorption measurements an elevated temperatures for two typical commercially available surfactants currently in use for such applications an alpha olefin sulphonate and a synthetic alkyl toluene sulphonate. Adsorprion experiments were performed in unconsolidated sand cores of temperatures ranging from 50 °C to 150 °C The role of clays in surfactant adsorption was investigated by comparing the results obtained in clean sand with those obtained in cores containing known amounts of clays.

Surfactant adsorption was de/ermined from surfactant concentration profiles at the core outlet. This analysis can be used for evaluating the whole adsorption isotherm provided a specific adsorption model (for example, the Langmuir isotherm) is assumed. Automatic history matching procedures for that purpose were tested and their efficiency evaluated.

The results show that adsorption of both surfactants in clean sand is relatively low and decreases with increasing temperature. The alkyl toluene sulphonate was found to adsorb more than the alpha olefin sulphonate, and its adsorption was more strongly affected by salinity. The presence of clays in the core resulted in increased surfactant adsorption.

Introduction

The injection of foam-forming surface active agents in steamflooding applications has the potential for improving the performance of this enhanced oil recovery (EOR) process by two mechanisms. It can improve conformance by reducing steam mobility in the steam zone, and it can increase the oil displacement efficiency in the swept zone. Irrespective of which mechanism is dominant, for economic reasons it is desirable to inject the lowest surfactant concentration which is still effective in improving oil recovery. The rate of propagation of dilute surfactant solutions through the reservoir may be strongly affected by adsorption of the injected surfactant on reservoir rock surfaces. Thus the evaluation of surfactant adsorption should always be included when assessing the effectiveness of the surfactant in improving steamflood performance. As the injection of steam may result in large temperature and salinity gradients in the reservoir, a complete evaluation of surfactant adsorption requires its measurement over a wide range of temperatures and salinities.

This paper describes the results of adsorption measurements for two types of commercially available foam-forming surfactants, an alpha olefin sulphonate and a synthetic alkyl toluene sulphonate. Adsorption of these two surfactants in unconsolidated cores saturated with either distilled water or a lowsalinity synthetic brine was evaluated at three temperatures. The solid used in the study was either a clean silica sand or a mixture of the sand and one of two types of pure clays montmorillonite and kaolinite.

Laboratory Evaluation of the CO2 Huff-N-Puff Process for Heavy Oil Reservoirs

Abstract

Laboratory tests were carried out to evaluate a CO2 huff-n-puff well stimulation process in a Lloydminster heavy oil reservoir. Two series of phase behaviour measurements were done on the reconstituted oil, each in a pressurization-then-liberation cycle. The first series was performed using CO2 as the carbonating gas. Some oil swelling occurred, and a large viscosity reduction was observed. CO2 was retained preferentially to CH4 during liberation and, consequently, reduced viscosities were maintained down to low pressures. The second series was carried out using a 1:3 mole ratio CH4/CO2, simulating the use of recycled gas in the huff-n-puff process. The results revealed that CH4 reduces the efficiency of CO2.

Core floods were performed and included evaluations of gas/water and oil/gas relative permeabilities at reservoir conditions, and an assessment of the longitudinal distribution of CO2 and the effect of soak period. Poor displacement efficiency was obtained by rapid CO2 injection, resulting in a low free gas saturation which was too small to provide the required amount of CO2 for effectively reducing the oil viscosity. The presence of a low mobile water saturation resulted in preferential displacement of water and enabled a somewhat more uniform longitudinal distribution of CO2 along the core.

Introduction

Primary production of oil in heavy oil reservoirs is usually low when compared to that of conventional oil reservoirs. Furthermore, heavy oil reservoirs often do not respond well to waterflooding. Accordingly, enhanced oil recovery methods have to be employed to boost production. Various techniques have been proposed in the literature such as thermal methods, polymer and caustic flooding, and gas injection.

Gas injection in heavy oil reservoirs is often applied in the huff-n-puff mode. Carbon dioxide is frequently selected as the stimulating gas because of its high solubility in the oil and its oil viscosity reducing characteristics. The work reported in this paper deals with laboratory tests carried out to characterize this process and help evaluate its applicability to an Alberta heavy oil reservoir. A brief literature survey is included in the next section. This is followed by a description of the phase behaviour studies, and then the core displacement studies. Finally, over-all conclusions are made based on the results obtained.

Literature Survey

There is an abundance of literature available on CO2 flooding of light oil reservoirs, whereas only a few papers have been published on CO2 stimulation of heavy oil reservoirs. For example, Reid and Robinson(l) reviewed the performance of the Lick Creek Meakin Sand Unit field project. This project consisted of a first phase in which producers and injectors were cycled. The second phase involved continuous injection of CO2, and the third phase consisted of alternate water-CO2 injection. Finally, water was continuously injected. They concluded that the project was successful and that the CO2/ water injection process was viable for relatively thin heavy oil reservoirs.

Stright et al.(2) described a single well test for a reservoir containing bottom water (Grand Forks Lower Mannville C Pool, Alberta).

Simulation of Miscible Displacement in Full-Diameter Carbonate Cores

Abstract

Miscible gas displacement data obtained from full-diameter carbonate reservoir cores have been fitted to a modified miscible flow dispersion-capacitance model. Starting with earlier approaches, we have synthesized an algorithm that provides rapid and accurate determination of the three parameters included in the model: the dispersion coefficient, the flowing fraction of displaceable volume, and the rate constant for mass transfer between flowing and stagnant volumes. Quality of fit is verified with a finite-difference simulation. The dependencies of the three parameters have been evaluated as functions of the displacement velocity and of the water saturation within four carbonate cores composed of various amounts of matrix, vug, and fracture porosity. Numerical simulation of a composite core made by stacking three of the individual cores has been compared with the experimental data. For comparison, an analysis of Berea sandstone gas displacement also has been provided. Although the sandstone displays a minor dependence of gas recovery on water saturation, we found that the carbonate cores are strongly affected by water content. Such behavior would not be measurable if small carbonate samples that can reflect only matrix properties were used. This study therefore represents a significant assessment of the dispersion-capacitance model for carbonate cores and its ability to reflect changes in pore interconnectivity that accompany water saturation alteration.

Introduction

Miscible displacement processes are used widely in various aspects of oil recovery. A solvent slug injected into a reservoir can be used to displace miscibly either oil or gas. The necessary slug size is determined by the rate at which deterioration can occur as the slug is Another commonly used miscible process involves addition of a small slug within the injected fluids or gases to determine the nature and extent of inter well communication. The quantity of tracer material used is dictated by analytical detection capabilities and by an understanding of the miscible displacement properties of the reservoir. We can develop such understanding by performing one-dimensional (1D) step-change miscible displacement experiments within the laboratory with selected reservoir core material. The effluent profiles derived from the experiments then are fitted to a suitable mathematical model to express the behavior of each rock type through the use of a relatively small number of parameters. This paper illustrates the efficient application of the three-parameter, dispersion-capacitance model. Its application previously has been limited to use with small homogeneous plugs normally composed of intergranular and intencrystalline porosity, and its suitability for use with cores displaying macroscopic heterogeneity has been questioned. Consequently, in addition to illustrating its use with a homogeneous sandstone, we fit data derived from previously reported full-diameter carbonate cores. As noted earlier, these cores were heterogeneous, and each of them displayed different dual or multiple types of porosity characteristic of vugular and fractured carbonate rocks.

Dispersion-Capacitance Model

The displacement efficiency of one fluid by a second immiscible fluid within a porous medium depends on the complexity of rock and fluid properties.

SPEJ

P. 647^