This paper presents the results of a study on the development of efficient methods for scaling of petrophysical properties from high resolution geological models to the resolution of reservoir simulation. These methods were evaluated using the data for Gypsy field located in northeastern Oklahoma near Lake Keystone. In this study, transmissibility between two grid blocks is the property that is scaled. After conducting the linear flow scale-up of transmissibility between two grid blocks, a scale-up of productivity index (PI) was found to be important and necessary in order to account for the radial flow around the wellbore. Special consideration was also needed for the pinch-out grid blocks in the system. Validity of the proposed approach was evaluated by comparing the performance prediction for various reservoir flow scenarios using finescale and coarse-scale reservoir models.
The oilfield Patos-Marinza, located in the southern part of Albania with an OOIP of approximately 2 billion bbls, is the biggest oilfield in the country. One intriguing feature of this heavy oil field is that it dips from outcrop in the hills to the south down to 2000 m over a distance of 17 km. The oil gravity improves accordingly from 6 °API up to 33 °API with the depth of the formation. Due to the broad range of depth and oil quality a multitude of enhanced oil recovery methods have been performed in the past, one being cyclic in situ combustion which was applied in the upper part of the reservoir.
In situ combustion, originally designed as flood patterns, has been practiced in the south of the field for about 20 years starting in 1973. Here the Driza formation is 450 m deep, oil gravity is 11 °API, and viscosity is approximately 9000 cp. Difficulties in production wells (lack of production, sand flow) prompted the state-owned operator, Albpetrol, to take remedial action in the form of cyclic in situ combustion for sand consolidation and production increase. Injection of 1200 - 3000 m?/d/well (cum. ± 200,000 m?/well) air resulted in a burned zone of approximately 5 m radius, and a stabilized reduction of sand inflow from 8 % down to less than 2 % was observed.
In successful applications the improved oil production was as high as 650 tons cumulative, and the subsequent oil production yielded considerably less sand content. Technical difficulties especially with burners resulted in two failures. Cyclic in situ combustion proved nonetheless to be a successful application to consolidate the formation sand around the wellbore and increase the oil production significantly.
Future successful development and exploratory drilling for gas will have to exceed current levels. Only three pools have been discovered in the last ten years that have initial marketable reserves of greater than 1500 E6M3. A positive correlation exists between the addition of gas reserves in the province of Alberta and the amount of exploratory drilling. Development drilling conducted for deliverability purposes does not substantially add to the reserve picture. However, exploratory drilling may result in large reserve additions. Future reserve additions translate into gas supply. By conducting scenario analysis of reserve growth based on ultimate potential estimates of 5600 E9M3 (200 Tcf) and 7600 E9M3 (270 Tcf), and comparing the results with current reserve growth levels, an assessment can be made of the province's ability to meet future market demand.
Following the 1996 success of two Single Well Steam Assisted Gravity Drainage, (SW-SAGD), wells in the Celtic Field, Saskatchewan, Mobil Oil Canada piloted a Dual Well Steam Assisted Gravity Drainage, (DW-SAGD), well pair in 1997. The well pair was located in the Sparky-General Petroleum, "channel" sands with a net pay thickness of about 20m and a dead oil viscosity of about 15,000 cP. The objective of the pilot was to obtain operational data for the design and drilling of horizontal wells, and the production performance of horizontal SAGD producers.
The well pair has now been operating trouble free for over a year. A plateau oil rate of about 100 m3/d has been sustained during this period, at an extremely efficient, Steam/Oil Ratio, (SOR), of just under 2.0.
This paper briefly reviews the geology and the reservoir in which the wells are located, specifics of well design and construction, surface facilities, start-up procedure and the performance of the wells.
This paper addresses the use of the Spearman rank coefficient, a nonparametric statistics, to estimate lateral autocorrelation and permeability trends. This approach provides an alternative to interference tests considering only production and injection rates. The objectives of this work are to validate this technique, point out its advantages/limitations and show results from its application to a field.
We performed a set of numerical experiments using a flow simulator and different synthetic permeability fields.. The results highlight the dependence of the proposed method on reservoir parameters. The method can indicate the presence of transmissibility barriers, permeability anisotropy and, in some situations, range anisotropy.
Next, we present a field case to demonstrate the application of the method. The Canto do Amaro field, located in the Potiguar basin, Brazil, is chosen because of a small well spacing and a previous comprehensive reservoir characterization study using geostatistics. The results obtained provide a better understanding of how the rank analysis can be used as an effective reservoir characterization tool.
This paper focuses on the fluid communication and injection responses in the Pekisko B Pool between January 1990 and September 1997. The analysis was based on responses of producers to changes in the injection rates. The strength of oil response is measured as the correlation between the oil rate and the injection rate. In a similar fashion, the strength of the total fluid responses is measured as the correlation between the total fluid rate and the injection rate. These responses and the corresponding time lags are presented in the form of special XY-diagrams. One form of these diagrams shows normalised responses of wells around each injector. The second form shows the long distance communication between injectors and producers that are characterised by strong responses above the predefined level.
Results indicate very good short and long distance communication between injectors and producers. Waterflood responses can be segmented into three geographical areas: northern, central and southern. The oil responses correlate strongly to the injection in the central part of the pool. Weaker responses and longer time lag response was observed in the southern pool area and strong interference between injectors was detected in the northern pool area. A more detailed analysis, involving pressure data, geology and completion intervals, demonstrate that the existing waterflood inefficiencies are related to inadequate injection volumes in the southern pool area and poor injection well distribution in the northern part of the pool. The study proved that the applied methodology is very efficient in diagnosing the waterflood performance and helping to optimise waterflood design.
THAI - "Toe-to-Heel" Air Injection, is a new EOR process, which integrates advanced technology and horizontal well concepts, to achieve potentially very high recovery of heavy oil. It can also realise very substantial in situ upgrading by thermal cracking, producing upgraded oil to the surface. The process operates in a gravity stabilised manner by restricting drainage to a narrow mobile zone. This causes the flow of mobilised fluids to enter directly into the exposed section of a horizontal production well. The process can be operated on primary production, as a new technology, as a followup to existing technologies, or as a co-process where the advantages of high thermal efficiency are required. This is achieved by concentrating the energy required for oil mobilisation, recovery and thermal upgrading in the reservoir. Combined with clean technology design, THAI offers a pathway to future economic success for the heavy oil industry.
Three-dimensional, semi-scaled experimental tests on light "Forties Mix" oil (30.7 API), Clair, West of Shetlands medium heavy oil (20.8 API) and heavy Wolf Lake oil (10.95 API) show that a well-controlled, narrow mobile oil zone is created just ahead of the combustion front. The width of this narrow zone depends on the characteristics of the heavy oil at reservoir conditions and the degree to which the very high viscosity of the cold oil seals the horizontal producer well. Well sealing can be augmented by a novel sleeve-back technique, which allows perforated downstream sections of the well to be shut-in. The application of this technique enabled the light oil test to mimic the operation of a heavy oil reservoir using THAI. Very high oil recoveries were achieved in the tests, up to 85% OOIP. During wet in situ combustion (ISC), Wolf Lake oil was upgraded to 20 API, achieving a reduction in the cold oil viscosity from 100,000 mPas to around 50 mPas.
The concept of the Toe-to-Heel Air Injection Process (THAI) is represented by the schematic in Fig. 1. Thus, a horizontal producer well is positioned in a line drive in the reservoir and air is injected via a horizontal injection well.
This arrangement is identified as HIHP. Alternatively, the injection well can be vertical (VIHP). This may be adequate, if the horizontal to vertical permeability allows good distribution of gas into the reservoir. Generally, a horizontal injector will provide a more uniform distribution of air across the inlet reservoir face of the line drive section. HIHP is considered to be the base-line well combination, which can be extended through the reservoir in a staggered line drive, HI2HP etc., by employing additional horizontal producer wells.
In Fig. 1, the combustion front is shown (ideally) as a "moving window", which traverses the horizontal production well, from the "toe" position, to the "heel". If such an ideal process could be implemented, then an essentially 100 per cent sweep would be obtained. This is obviously a desirable target efficiency to be aimed for in any advanced EOR process.
SAGP is a thermal oil recovery process that is similar to Steam-Assisted Gravity Drainage (SAGD) but which involves the addition of a small concentration of a non-condensable gas to the steam. This paper is a continuation of parts 1 and 2 presented at the 48th and 49th Annual Technical meetings of the Petroleum Society.
Theoretical developments and laboratory experiments continue to show significant improvements for the process as compared to SAGD. Experimental results have now been obtained with Athabasca crude oil as well as Cold Lake and Lloydminster type oils.
In SAGP much of the oil displacement is caused by the flow of fingers of gas/steam rising counter-currently to the draining oil, rather than by the simple advance of a continuous steam chamber. The rising gas fingers raise the pressure in the reservoir above and this increase in pressure towards the top of the reservoir tends to push the oil down. Gas accumulates in the upper part of the reservoir and oil drains to the production well near to the bottom. The mechanism is discussed in the paper together with results from recent scaled, physical model experiments.
The work demonstrates that SAGP may be expected to produce oil at rates nearly equivalent to SAGD but with much lower steam consumption.
Viscous fingering takes place when the viscous forces of a displacing phase has greater momentum than that of the displaced phase. Viscous fingering is an extremely important phenomenon in many applications of enhanced oil recovery, underground liquid waste disposal, and geothermal energy production. While the onset and propagation of viscous fingers during liquid-liquid displacement is considered to be of severe engineering consequences, little has been done to mathematically model the onset and propagation of a viscous finger. Viscous finger under double diffusive conditions is even scarcer. In this paper, two-dimensional non-linear double diffusive convection in a multi-porous cavity is considered, both numerically and experimentally. The Darcy equation, including Brinkman term to account for the viscous effects, is used as the momentum equation. The model consists of two rectangular cavities filled with a porous medium. The smaller cavity is located at the top of the larger one. The larger cavity is filled initially with glycerin while the smaller one contains fresh water. At the initial time, the fresh water is injected with either constant flow rate (numerical) or constant hydrostatic head (experiments) and the viscous fingering formation is studied in details. The momentum, solutal, energy and continuity equations are solved numerically using the finite element technique. This transient problem is solved to study the thermal displacement, the isothermal displacement and the microgravity displacement of glycerin by water to understand the onset and the propagation of viscous fingering. For each case, the variation of the distance between the tip of the finger with time is studied in details. The effects of aspect ratio and displacement velocity are studied, both in the context of onset and propagation of viscous fingers. Experimentally, an ingenious method is developed for visualizing 2-D flow in a porous medium. A carbonate formation is used as the porous medium. A chemical dye is used to delineate the propagating front of a viscous finger. Initial series of experiments are conducted under isothermal conditions.
The effect of hydrocarbon gas injection on oil production during Steam Assisted Gravity Drainage (SAGD) projects was investigated using numerical simulation. The results indicate that oil production rates as well as total oil production are significantly reduced when gas is injected with steam from the early period of a SAGD operation. This is because most of the injected gas gathers at the upper part of the leading edge of the steam chamber and prevents the growth of steam chamber there, which results in a reduction of ultimate oil recovery.
However, if the gas injection is initiated during later periods of the process, an improved steam oil ratio is obtained without significant reduction in oil production rates and the total oil production. In this case, the injected noncondensable gas migrates to the upper part of the reservoir and does not prevents the growth of steam chamber since the chamber had already grown to the desired size.
Gas injection slows down the growth of steam chamber in the upper part of the reservoir and induces its growth downwards. This mode of growth of steam chamber results in an improvement in steam oil ratio as is illustrated in this paper. An understanding of this mechanism and its optimal timing are important in enhancement of the SAGD process.