A steam chamber generally rises steadily in the channel sands of Athabascaoil sands during a SAGD operation.It is commonly known that steam chambergrowth rate is mainly dependent to permeability.Once the steam chamberreaches the upper boundary, it starts to expand laterally.This is thebasic concept of steam chamber growth of SAGD process in fine sands.
However, the growth of steam chamber measured through the analysis oftemperature changes from observation wells behaves different in many instancesthan the commonly accepted steam chamber growth concept, explainedabove.In these observation wells, the steam chamber deviates from theusual behavior; sometimes stops and then resumes rising or shrinking, or evendisappears during SAGD process.This can be caused by the specific natureof steam fingering phenomenon during SAGD operation.
Many simulation studies have been conducted to understand the steam risingphenomenon during SAGD operations.At the top of the steam chamber, steamfingers seemed to be created where steam flows through and the steam chamberexpands vertically.If steam fingering actively develops, steam chambergrows steadily as expected.However, activity of fingering can bedisturbed under certain conditions, which can result in various alterations inthe growth of steam chamber.
In this paper, the steam fingering phenomenon during SAGD process isdiscussed with actual measured field data from four SAGD projects; UTF Phase A,UTF Phase B, Hangingstone and Surmount.
There is an abundance of natural gas being discovered and produced that is slightly sour.According to a US Department of the Environment (DOE) survey that includes Canada, about 80% of current and new gas has a hydrogen sulphide (H2S) concentration of 1% or less. Of course, this must be treated to remove the H2S to meet sales gas specifications.For small scale (less than 50 - 100 kg) and large scale (greater than 20 tonne/d) of equivalent sulphur, current technologies appear reasonable.Conversely, for intermediate range (0.1 - 20 tonne/d) equivalent sulphur, current technology has proven to have high capital and/or operating costs and some processes are difficult to operate. Therefore, there is a need for an intermediate scale (0.1 to 20 tonne/d) process with lower capital and operating cost than those currently available. The applications of such a process range from the removal of H2S from acid gas at low pressure produced from the amine process to high pressure raw sour gas. There are additional challenges from sour gas associated with heavy oil thermal projects in that it is at low pressure and contains substantial C7?. The elemental sulphur produced should be of sales grade quality such that the handling of the product can fit into the existing sulphur infrastructure and sold into existing markets. Otherwise, disposal of the product becomes costly and in some cases becomes another environmental problem.
In answer to this need, Xergy Processing Inc. has developed a gas phase direct oxidation process for the above applications as well as treating heavy oil off-gas, fuel gas, power generation gas.The process has relatively low capital and operating costs and is easy to operate, with no equipment that is unfamiliar to the petroleum industry.Conversion to sulphur depends on the process configuration and pressure but ranges from 80% to 99.9+% based on lab and field data.
Much of the design basis for well structures subjected to high amplitude cyclic loading is based on material assumptions that extrapolate strength properties from uniaxial, monotonic tests to conditions where cyclic, multiaxial stresses are imposed. This paper shows results from cyclic testing on common Oil Country Tubular Goods (OCTG) materials and demonstrates the difference between physical behavior measured under cyclic loading conditions and theoretical behavior extrapolated by numerical modeling of uniaxial, unidirectional test data. Modeling theories for plastic deformation are discussed, along with their limitations and relevance in a cyclic loading environment. The implications of these limitations for design choices in thermal wells also are discussed.
Fatigue properties for the high-amplitude, low cycle application of thermal operations have not previously been investigated in much depth, in particular for OCTG. Along with characterizing cyclic mechanical properties, the tests discussed here also were used to assess the low-cycle fatigue properties of steel commonly used for in thermal well casings. Consistent fatigue results were produced, which, applied in the context of analysis results using representative cyclic mechanical properties, provide a basis for estimating fatigue life for specific cyclic deformations. Depending on scenario assumptions, substantial statistical variation in fatigue life can be expected, so exact fatigue life predictions are not anticipated. The primary value in such modeling capability is the assessment of mitigation options for extending well life when casing deformations are indicated.
The paper also discusses some practical implications of the difference between actual material behavior and idealizations used for modeling purposes. An example application of the cyclic material behavior and fatigue life prediction is also included.
Bubble nucleation, growth and mobilisation of gas are important phenomena encounter in oil production by the depressurisation process.The drive energy for oil production during pressure depletion is supplied initially by oil expansion but mainly by gas evolution from solution and expansion of reservoir fluids.Some heavy oil reservoirs in Venezuela and Canada show a high recovery factor during primary production under the solution gas drive process.Factors responsible for high oil recovery in heavy oil reservoirs are not well understood to allow reliable predictions to be made for economic evaluation of the process.A series of flow visualisation tests at the pore level was conducted using a high-pressure glass micromodel to identify the key features of the process.
A heavy crude oil, with a viscosity of 2500 cp at the bubble point pressure and API of around 10, was used to perform the tests at reservoir conditions. Micromodels with realistic pore pattern and different wettability characteristics, including oil-wet, water-wet and mixed-wet were used in the tests.A series of experiments was performed to study the effect of depletion rate, saturation history and water presence on the nucleation process, gas evolution and hydrocarbon movements.
Our observations highlighted the significance of test conditions, particularly saturation history and operational conditions on the nucleation process and bubble formation.Laboratory tests can produce a large number of bubbles formed by pre-existing micro bubbles activation, or a limited number of bubbles due to bulk nucleation, resulting in widely different depressurisation results.Hence, interpretation of laboratory data and its application to field performance would require particular considerations as identified in this study.
Critical gas saturation and subsequent gas/oil production are strongly affected by the critical value of supersaturation and the number of bubbles formed during depressurisation. Two generalised correlations have been developed to predict the above parameters at realistic reservoir conditions.
The experimental data generated in this study and interpretation of the results provide information on gas nucleation, critical supersaturation, bubble density and critical gas saturation, which are essential in field development planning and estimation of oil and gas recovery by depressurisation. The study also clears a number of ambiguities in the literature on prevailing mechanisms in depletion of heavy oil and contradictions between laboratory and field results.
Guo, Jianchun (Southwest Petroleum Institute) | Zhao, Jinzhou (Southwest Petroleum Institute) | Chen, Lingming (Northwest Petroleum Bureau of Sinopec) | Li, Yomgming (Southwest Petroleum Institute) | Fu, Ying (Southwest Petroleum Institute)
The Ordovician carbonate reservoir in Taliram Basin is typical of fractured and caved reservoirs with thick oil layer, high temperature, deep zone and extra heterogeneity together with high density, high viscosity and high freezing point et al as common characteristics of crude oil. More than 80% wells have to be stimulated before economically producing. Based on the laboratory researches and plentiful field practices, the following stimulation modes are formed: the multiplayer acid-fracturing for long open-hole interval or layered acid-fracturing, height-control acid-fracturing against bottom water coining, a combination of hydraulic fracturing and acid fracturing. On the basis of drill so&g, logging data, well-recorded data and some geophysical data such as change rate of logging amplitude, cohere body and Jason reversion et al., model for well selecting and layer appraising is developed. We develop high-visco gelling acid, retarded acid based on surfactant, low friction resistance emulsified acid as well as insitu stiffening acid, with better retardancy, low leakage and low friction as the result, with which the damage near the wellbore is effectively solved and deeply penetrated acid-etched fracture is obtained. Furthermore, the 3D acid fracturing optimization design techniques for fractured and caved reservoir brought forward in this paper have accurately calculated the treatment data and fracture geometry, thus the effectiveness of acid fracturing is increased a lot. Up to the end of 2003, more than 220 times of application of acid-fracturing in Ordovician Carbonate Reservoir of Tahe Oilfield located in the northeast of Taliram Basin of China have indicated that 98.8% were effective, with average single-well incremental yield of 60t/d and the period of validity over 250 days, therefore, Tahe oilfield has increased the production about 311.8×10t altogether.
Tahe Oilfield, which lies in Kuche and Luntai County of Xinjiang, China, is a large marine carbonate reservoir found by Sinopec.This Ordovician reservoir, with depth of 5400~6300m, is characteristic of large layer span, strong heterogeneity, high reservoir temperature above 120°C and high oil viscosity et al. Many wells are of low nature yield and well stimulation is a key technique for both high yield and steady production.
Considering characteristics of the geology and stimulation technology, suitable acid-fracturing for deep well and large interval of Tahe oilfield is recommended, based on the synthetical researches on stimulation technology, acid-fracturing design model and acid system. Retarded acid system with high viscosity and low friction is developed and a novel leakoff model for fractured and caved reservoir is established. Coresponding matched wellbore production technology is also presented. In this paper, all of the above are described as well as their successful application in Tahe Oilfield.
Characteristics of Reservior Geology and Fluid
Tahe oilfield is located in the southwest of Akeku Pimpling in Shaya Hunch in Taliram Basin, where Triassic, Carboniferous and Ordovician formation show good oil&gas. The combo, with reservoir bed of Lower Ordovician karst f fractured and caved reservoir and capping bed of Upper Carboniferous mudstone, is one of most primary ones. Ordovician formation, controlled by noselike Akekule Pimpling and laterally by compact carbonatite, belongs to unconformable fracture-aperture combination trap. Up to October 2004, in Ordovician formation of Tahe Oilfield, Blocks 2, 3, 4, 6, 7 and 8 have been proven up, with the superposition areaof 381.1km2 andOIP ofover 2×10t.
The objective of this paper is to investigate the transient pressure behavior of Cold Heavy Oil Production (CHOP) wells with the consideration of wormhole configurations and foamy oil flow. Wormholes provide main conduits for foamy oil flow in the production process, and foamy oil is highly compressible owing to the dispersed and encompassed gas bubbles. This study proposes a comprehensive model to describe the transient flow of matured CHOP wells. Then, the transient pressure behavior has been extensively analyzed. The model not only provides reliable transient pressure responses of matured CHOP wells, but also offers a way to estimate the possible wormhole configurations and to understand the possible pressure drop along wormholes.
Fresh water scarcity and increasing demand are worldwide concerns and arebeing addressed by a number of water man-agement initiatives in Alberta andCanada.In 2003, 0.3 bil-lion m3 of produced water was injected intodisposal wells associated with oil and gas production in Alberta.Thisvol-ume of water is a potential resource for recycling and benefi-cial reuse inAlberta, which would have a significant impact on sustainable development inAlberta. This water must first be treated to meet water qualityrequirements and regulatory guidelines for specific applications.Thispaper provides a comprehensive technical and economic review of watertreat-ment technologies and shows that water treatment processes arecommercially available.Although the cost of implement-ing suitabletreating processes to meet drinking water quality guideline is estimated atthree times the current cost of mu-nicipal water supply in Alberta, it is morefeasible to recycle produced water for other purposes, such as agricultural orpe-troleum application (i.e., waterflooding, etc.).This is because waterquality guidelines for most other applications are not as stringent as that fordrinking water and there is increasing pub-lic resistance for industry to usefresh water for commercial applications. A multi-disciplinary researchand development team studying water recycle and beneficial reuse is necessaryto look into these issues. The University of Calgary is set tocollaborate on such projects due to the current research em-phasis onsustainable energy and environmental impact. Col-laboration between thegovernment, industry and academia to develop initiatives aimed at reducingfresh water is possible in Calgary for several reasons.One is theproximity of many major oil and gas companies in this city, which would allowfor easy communication.Another is the fact that the current price of oilwould not inhibit producing companies from in-vesting in this kind ofresearch.The result can be well-developed initiatives to treat andrecycle produced water for beneficial reuse, thus reducing fresh water demandfor many applications in the petroleum and agricultural industries.
Every day, approximately 800 million cubic feet of gas is burned in the oil sands region of Alberta in the extraction and processing of heavy oil and bitumen (see Figure 1).The vast majority of this energy is used in the creation of steam for Cyclic and SAGD oil production processes for bitumen extraction from the oil sands.One of the main factors limiting further expansion of the oil sands and heavy oil development in the region is natural gas usage.
A dependable and predictable energy source is required for continued development of heavy oil and oil sands production in Alberta.Natural gas is currently the preferred source; however, the future availability of a natural gas supply for the region and the cost of that supply are unknown variables with significant economic ramifications.Economic justification of new projects under such conditions is, at best, challenging.
Alberta, and clearly the world, is sitting on a virtually unlimited supply of usable geothermal heat energy that would be an attractive solution to the oil sands energy source problem.The green aspects of geothermal energy are appealing for both ethical and political reasons.Of even greater importance to the bitumen producer is that geothermal energy has the potential to provide a significantly positive impact to project economics - the future availability of an energy source that is guaranteed and at a known cost.
We present two versions of a Darcy-scale model for simulation of the solution gas drive in heavy oils.
Presence and behaviour of a foamy-oil effect appears to be critical to the cold production process. This process is not a well-understood production mechanism because a wide range of different petrophysical parameters and experimental factors interact in a rather complex way. Over the past few years, a number of efforts have been made, in many institutions, in order to understand and model the solution gas-drive mechanism in primary heavy oil recovery. Conventional simulations succeed in matching actual field productions but are not reliable for prediction forecast purposes (large uncertainties on recovery factors). We present an evolving nucleation and flow model for solution gas drive in heavy oil.
The model is built at the Darcy scale and involves the effect of capillarity on bubble flow and phase change. An ad hoc simulation tool is built to analyze carefully the properties of the model. The tool allows to reproduce laboratory experiment across a sample rock.In the limit of infinitely slow depletion, an asymptotic theory is constructed that allows to predict analytically the pressure difference across a sample. The theory predicts a pressure gradient at first order without additional calculation, and the gradient appears, at first order, independent on the gas formation (degassing) kinetics. No saturation gradient is predicted at first order. The results are compared to numerical simulations and experiment, and good agreement is found in cases where the pressure gradient is known.
In a second version of our model we introduce the effect of capillarity on bubble growth. Capillarity delays bubble growth by stabilizing small bubbles under a certain critical radius. This new term leads to nucleation fronts propagating rapidly through the sample.
It appears more difficult to predict a saturation gradient. The causes of this difficulty are analyzed.
Many efforts have been made recently to understand and model the solution gas drive mechanism in primary heavy oil recovery. Present day models are unreliable, as even though conventional simulations can succeed in matching field productions, they fail to capture the actual physics of the solution gas drive process in heavy and extra-heavy oils. A "foamy-oil" effect related to the bubbly aspect of recovered oil, enhanced oil recovery and higher critical gas saturation has been identified by some authors5,9 but its physical nature is not quite elucidated.
In order to better understand the physics of solution gas drive, several experiments have been conducted at the laboratory scale. In this work we attempt to simulate the experiments reported by Bayon et al.[1,2] .The flow rate is imposed so that the pressure decreases in an approximately linear fashion over the duration of the experiment. These experiments were performed under X-ray scan to record the saturation profiles all along the core during the depressurization.
It was attempted to model the results of the experiment using both classical Darcy scale models such as those of the Stars® and Eclipse® simulators, and a modified model. Two main difficulties arose
(a) Relative permeabilities have to be adjusted as a function of the rate of decrease of the pressure or depletion rate. In other words, relative permeabilities matched for one depletion rate do not match the results for the other depletion rate. This is a classical difficulty in heavy oil modeling.
(b) Measured saturation profiles differ from simulated ones. The measured profiles have marked spatial variations or gradients (this was observed by Egermann et al., Sahni et al., as well as by Bayon et al.[1,2] whose data are reproduced here on Figure 1). On the other hand the simulated profiles are flat. This effect has been confirmed with other models and codes
Breccia is a lithological facies present in the McMurray Formation of the Athabasca oil sands of northeast Alberta.It consists of mud or shale clasts embedded in clean sands.The mud content of this facies varies from 0-100% and the clasts range in size from millimetres to metres with varying degree of angularity and sorting.Breccia is common in bitumen reservoirs.From an in-situ recovery perspective, breccia can alter fluid flow and reduce the overall oil saturation due to the presence of the mud clasts.To properly characterize the reservoir flow properties, it is necessary to develop a systematic procedure to assign the vertical and horizontal permeability of breccia zones on a scale that is suitable for the numerical simulation of recovery methods such as steam-assisted gravity drainage (SAGD).
A methodology to calculate the 2-D permeability of breccia facies from core photographs and mathematical theory has been described in a previous paper. However, core photographs do not capture the three dimensional nature of the mud clasts in the breccia.In this paper, the 2-D theory is extended to 3-D by treating the mud clasts as impermeable ellipsoids.The effective permeability of breccia regions may be calculated from the permeability of the sand in which the mud clasts are embedded if the size and orientations of the clasts are known.As for the 2-D case, the results from theory are in satisfactory agreement with those from flow simulation.Using the theory specialized to the case of oblate spheroidal clasts, a procedure is developed to estimate the 3-D permeability of breccia regions, based on 2-D information from core photographs.The paper concludes with guidelines for systematic permeability assignment in the breccia zones of the oil sands as well as other similar formations.