Southeast Saskatchewan Research Articles

Stratigraphy and lithologic heterogeneity in the Mannville Group (southeast Saskatchewan) defined by integrating 3-D seismic and log data

Abstract Wireline log and 3-D seismic data were integrated to define stratigraphic units and lithologic heterogeneity in the Mannville Group of southeast Saskatchewan. The Mannville in this area is a stratigraphically complex unit formed of fluvial to marine deposits that, although non-prospective for hydrocarbons in this area, share many similarities with time-equivalent strata in areas of heavy oil production. Seismic sequence stratigraphic principles permitted us to subdivide the Mannville into three packages. The ability to visualize the 3-D seismic data in a variety of ways, including arbitrary lines and stratal or horizon slicing techniques, helped us to define stratigraphic features that would affect fluid flow in hydrocarbon producing areas. These features include channels of various sizes and orientations, and channel elements such as scroll bars and lateral accretion surfaces, that are present within specific portions of the Group. Because the effectiveness of enhanced recovery methods such as steam-assisted gravity drainage depends on a development team's ability to recognize reservoir heterogeneity, similar integration of 3-D seismic, well logs and other data types would assist greatly in developing the Mannville in heavy oil areas. There is close, but not one-to-one, correspondence between the stratigraphic units we defined and those established by regional log- and core-based correlations. Seismic resolution problems or log correlation styles could be responsible for the differences.

Horizontal Well Infill Development of the Manor Spearfish Field

Abstract The Manor Spearfish Field, located in Southeast Saskatchewan, was originally discovered in 1987, with the drilling of several vertical wells that encountered remnant Spearfish sands on top of the Alida carbonates. A few vertical wells were produced at low rates. In 1992, several companies aggressively developed the pool entirely through horizontal drilling. Production peaked at 1,100 m3/d, then declined to just over 110 m3/d. The pool has been the target of recent horizontal infill drilling. Several successful wells have been drilled, and Spearfish production from Crescent Point Energy operated wells has doubled from under 100 m3/d to almost 200 m3/d. Additional infill locations remain, both with new stand-alone horizontal wells and with horizontal re-entry wells. This paper reviews the predicted and actual results of five horizontal infill wells drilled in 2002. The methodology used in prioritizing the infill locations is also intended to illustrate the basic principles of reservoir engineering, and how they can be applied through simple analytical methods to yield favourable results. The paper, as such, provides a review of the basic engineering steps needed in a successful infill well development project. Background The Manor Spearfish Field is located approximately 3 km southwest of the town of Manor, Saskatchewan. It consists of Triassic aged Spearfish sands, [also called Lower Watrous or Amaranth sands(1)], which on-lap the Mississippian erosional surface and form reservoir grade sand bodies up to 8 m in thickness. The primary sands are the P-2 Lower or "C" sand and the P-2 Upper or "B" sand. The two sand layers vary from 1 to 3 m, with the thinner sands having more anhydrite occlusion and dolomite cementation. Porosity varies between 15 - 18%, and permeability varies between 5 - 25 mD. The top seal is formed by the impermeable overlying terrestrial Red Beds. Oil is sourced and charged from the underlying Alida beds, due to the absence of effective Mississipian cap-rock. The target of horizontal drilling is the P-2 Upper sand. There is some separation between the Upper and Lower P-2 sands in places, but it appears that there is likely communication through the barrier. There are also various amounts of separation between the Alida and the Lower P-2 sand. Pool Performance The pool was discovered in 1987 and production commenced from several vertical wells. Production was never very prolific, due to the low permeability nature of the reservoir. Figure 1 illustrates a map of the field and outlines the location of the horizontal infill wells. During the horizontal drilling boom of the early 1990s, the pool was aggressively developed, entirely with horizontal wells. Production dramatically increased and peaked in 1992, at approximately 1,100 m3/d. It should be noted that total production presented here is for Crescent Point Energy operated wells, only because the data is more current. Thus, the Spearfish production operated by Crescent Point peaked at 950 m3/d. Production then declined in an apparent harmonic fashion; rapidly at first, then leveling off at slower decline rates.

A Swainson's hawk staging area long the Missouri Coteau in southeast Saskatchewan

A Swainson's hawk staging area long the Missouri Coteau in southeast Saskatchewan

The third Canadian workshop on fusarium head blight, Winnipeg, Manitoba, 2003 / Troisième colloque canadien sur la fusariose, Winnipeg, Manitoba, 2003

The third Canadian workshop on fusarium head blight, Winnipeg, Manitoba, 2003 / Troisième colloque canadien sur la fusariose, Winnipeg, Manitoba, 2003

Early Proterozoic geomagnetic field in western Laurentia: implications for paleolatitudes, local rotations and stratigraphy

Abstract The east-west trending, post-orogenic subvertical Cleaver Dykes from the Great Bear Magmatic Arc are dated by the U–Pb (baddeleyite) method to be 1740 +5/−4 Ma. They have a mean direction of magnetization of D, I=136.5 and 57.4°, k=64, α95=4.5°, based on samples from 17 diabase dykes, a mean location 65.7°N, 118.03°W, and a corresponding paleopole at 19.4°N, 83.3°W, A95=6.1°. Studies of baked contacts, country rocks distant from dykes, and later intrusions that cut them, show that the dykes became magnetized soon after intrusion. The paleopole is not significantly different from that obtained from the 1759±1 Ma post-orogenic Jan Lake Granite from the Hudsonian Orogen in southeast Saskatchewan. These paleopoles fall among a cluster previously determined from post-orogenic overprints in a wide variety of rocks and geological settings across Laurentia. Their mean is 20.8°N, 94.5°W, A95=5.2°. Collectively they record a widespread remagnetization episode following the Hudsonian Orogeny, during which the polarity of the field remained constant. This single polarity interval (the Cleaver Superchron) has a mean age of approximately 1747 Ma, and its duration is at least 13 million years but is probably much longer. With further refinement, it could become a global statigraphical marker. There are 18 paleopoles from red beds and igneous rocks which record the paleofield in western Laurentia mainly over an extended interval we estimate to be at least 100 million years between about 1960 and 1830 Ma during the Hudsonian Orogeny. Over this interval, western Laurentia remained at a low and essentially constant latitude. Reversals of the geomagnetic field occurred opposed magnetizations being of approximately equal frequency; there are numerous magnetochrons which could, in future, assist in regional stratigraphic correlations. On the basis of six studies, we estimate that the reference paleopole for this interval is at 1.1°S, 71.7°W, A95=12.1° (N=6). Paleopoles from the other 12 studies are spread over a 100° arc indicating large variable rotations about local vertical axes which probably resulted from transcurrent faulting caused by indentation of the bordering Archean Slave and Superior cratons during the Hudsonian Orogeny. These reference paleopoles show that during the Hudsonian Orogeny, western Laurentia was in paleolatitudes of 15–30°. During post-Hudsonian time (ca. 1750 Ma) paleolatitudes were about 20° higher. Paleowind directions inferred by others, indicate that Laurentia during these intervals was in the northern hemisphere.

Pool characterization of Ordovician Midale field: Implication for Red River play in northern Williston basin, southeastern Saskatchewan, Canada

The Upper Ordovician Midale field is located in the northern Williston basin in southeast Saskatchewan, Canada. Hydrocarbons are hosted mainly in the dolomite reservoirs with burrowed textures in the upper Yeoman Formation. These reservoirs are characterized by intercrystalline porosity in the dolomitized matrix, with variable amounts of vugs and fractures, and can be divided into four zones. Reservoir zones 1 and 2, typically 6–10 m (20–33 ft) thick in total, are situated in the upper part of the traps and commonly bear oil. Although the underlying zones 3 and 4 are thicker, they commonly contain only water because they are located below the spillpoint of the hydrocarbon traps.The seismic reflection of the Red River reservoirs in the Midale field is characterized by a weak- to medium-amplitude trough immediately above the positive reflection of the Winnipeg shale. Where all four zones are present, an additional peak occurs on the seismic profile above the original reservoir reflection. This additional peak, however, disappears where reservoir zones 3 and 4 pinch out. Where there is an increase in the thickness of reservoir zones 1 and 2 or amalgamation of zone 1 with zone 2, the Red River reservoirs are characterized by high-amplitude and high-frequency reflections on seismic profiles.The Ordovician oil pools in the Midale area are associated with low-relief anticline structures. These low-relief structures are interpreted as the compactional drape of Red River strata over local Precambrian basement highs. The source of hydrocarbons in the Red River reservoirs is Ordovician kukersites. A wide range of API fractions for the oils from the Midale pools suggests a mixing of low-maturity oils, sourced from local kukersite beds, and high-maturity oils that migrated over a long distance from the south. The hydrocarbon production from Red River Midale pools is characterized by the fast rise of water cut and high water output, which can be attributed to the small pool size and the fracture systems connecting oil and water zones.

Coreflood Studies of Tertiary CO2 Flood in Naturally Fractured Midale Formation in Southeast Saskatchewan

Abstract The distinctive geology of the Weyburn and Midale reservoirs has important implications for the design of a CO2 injection process for these fields. They are contained within two distinct zones of the Mississippian Carbonate formation; the tight, high-porosity Marly zone sits on top of the low-porosity Vuggy zone. The latter zone has a higher permeability, and is more extensively fractured vertically, than the Marly zone. These geological features result in a relatively unswept Marly zone after waterflooding. The Marly/Vuggy sequence presents an opportunity for a CO2 flood to take advantage of gravity segregation to recover the large remaining oil target in the Marly zone. A series of coreflood tests were conducted to simulate tertiary CO2 injection in the Marly/Vuggy zones in the Weyburn and Midale reservoirs. Berea cores with different permeabilities were split lengthwise. The halved segments of the core were butted together to represent the Marly and Vuggy zones. Water (in waterflood mode) and CO2 (in tertiary CO2 flood mode) were injected into the bottom high-permeability section of the dualpermeability core. The coreflood results showed that, in the tertiary CO2 flood, CO2 could migrate to and recover the oil from the top low-permeability zone which was poorly swept by the waterflood. Also, the effects on tertiary oil recovery of operating pressure, injection rate, and permeability contrast could be significant. Introduction The Weyburn and Midale reservoirs in southeast Saskatchewan hold light and medium gravity oil in fractured, low permeability Midale Beds. These reservoirs are contained within two distinct zones of the Mississippian Carbonate formation: the tight, highporosity Marly zone sits on top of the low-porosity Vuggy zone. The latter zone has a higher permeability, and is more extensively fractured vertically than the Marly zone. These geological features result in a relatively unswept Marly zone after waterflooding. It is believed that the distinctive geology of these reservoirs has important implications for the design of a CO2 injection process for these fields, i.e., the Marly-Vuggy arrangement of the reservoir offers potential to utilize gravity segregation effects to enhance oil recovery. Numerical analyses(1, 2) of tertiary CO2 injection in these naturally fractured reservoirs showed that CO2 injected into the lower, more permeable Vuggy zone can contact and mobilise a large amount of oil in the Marly, which has remained relatively unaccessed by waterflooding. A coreflood program was designed at Saskatchewan Research Council (SRC) to address the CO2 injection process in Weyburn reservoir and comparable fields. Laboratory core displacement tests were conducted with a dual permeability split Berea core representing the Marly and Vuggy zones of a reservoir. Some preliminary results reported in a previous paper(3) showed that CO2 injected into the Vuggy zone could rise to the upper Marly zone, and that the potential to recover incremental oil by a tertiary CO2 slug flood is high. After the technique of butting the core halves was improved, the several additional tertiary CO2 coreflood tests reported here were performed with Weyburn reservoir fluid at 63 ° C (reservoir temperature) to confirm the previous finding.

A comparison of CO 2 minimum miscibility pressure determinations for Weyburn crude oil

Minimum miscibility pressure (MMP) is often used as a key criterion for screening and selecting suitable solvents for enhanced oil recovery projects. This paper compares the pure and impure CO 2 MMP values determined for a medium oil from Weyburn reservoir located in southeast Saskatchewan, Canada. Three different methods were employed for determining MMP, namely, slim tube experiments, rising bubble apparatus (RBA) tests, and correlations. The contaminants in the impure CO 2 streams considered were nitrogen (from flue gas) and methane (from recycled CO 2). Results of the study indicated that the MMP values measured by the RBA technique agreed well with those measured using the slim tube tests and those predicted using a published correlation. For the Weyburn oil–CO 2 system, a distinct bubble behaviour—tail formation—was observed when the pressure reached or was higher than MMP. These results provide additional experimental experience of using the RBA as an efficient tool of determining the MMP for some solvent gas–medium oil systems. This study also demonstrated that, for the Weyburn reservoir, promising EOR agents (having an MMP below 80% of the reservoir fracture pressure) are pure CO 2 and blended CO 2 containing up to about 12 mol% CH 4 or 5 mol% N 2.

Devonian hydrocarbon source rocks and their derived oils in the Western Canada Sedimentary Basin

Research Article| March 01, 2001 Devonian hydrocarbon source rocks and their derived oils in the Western Canada Sedimentary Basin* Martin G. Fowler; Martin G. Fowler Geological Survey of Canada, 3303 - 33 Street NW, Calgary, AB, T2L 2A7 Search for other works by this author on: GSW Google Scholar Lavern D. Stasiuk; Lavern D. Stasiuk Geological Survey of Canada, 3303 - 33 Street NW, Calgary, AB, T2L 2A7 Search for other works by this author on: GSW Google Scholar Mark Hearn; Mark Hearn Shell Canada Ltd., 400 - 4 Avenue SW, Calgary, AB, T2P 2H5 Search for other works by this author on: GSW Google Scholar Mark Obermajer Mark Obermajer Geological Survey of Canada, 3303 - 33 Street NW, Calgary, AB, T2L 2A7 Search for other works by this author on: GSW Google Scholar Author and Article Information Martin G. Fowler Geological Survey of Canada, 3303 - 33 Street NW, Calgary, AB, T2L 2A7 Lavern D. Stasiuk Geological Survey of Canada, 3303 - 33 Street NW, Calgary, AB, T2L 2A7 Mark Hearn Shell Canada Ltd., 400 - 4 Avenue SW, Calgary, AB, T2P 2H5 Mark Obermajer Geological Survey of Canada, 3303 - 33 Street NW, Calgary, AB, T2L 2A7 Publisher: Canadian Society of Petroleum Geologists Received: 12 Sep 2000 Accepted: 16 Nov 2000 First Online: 02 Mar 2017 Online ISSN: 2368-0261 Print ISSN: 0007-4802 © The Society of Canadian Petroleum Geologists Bulletin of Canadian Petroleum Geology (2001) 49 (1): 117–148. https://doi.org/10.2113/49.1.117 Article history Received: 12 Sep 2000 Accepted: 16 Nov 2000 First Online: 02 Mar 2017 Cite View This Citation Add to Citation Manager Share Icon Share Facebook Twitter LinkedIn MailTo Tools Icon Tools Get Permissions Search Site Citation Martin G. Fowler, Lavern D. Stasiuk, Mark Hearn, Mark Obermajer; Devonian hydrocarbon source rocks and their derived oils in the Western Canada Sedimentary Basin. Bulletin of Canadian Petroleum Geology 2001;; 49 (1): 117–148. doi: https://doi.org/10.2113/49.1.117 Download citation file: Ris (Zotero) Refmanager EasyBib Bookends Mendeley Papers EndNote RefWorks BibTex toolbar search Search Dropdown Menu toolbar search search input Search input auto suggest filter your search All ContentBy SocietyBulletin of Canadian Petroleum Geology Search Advanced Search Abstract Devonian strata within the Western Canada Sedimentary Basin contain large reserves of oil and gas. These vast hydrocarbon reserves can be largely attributed to the occurrence of abundant mature, excellent to good quality Devonian source rocks. The Middle Devonian Elk Point Group contains several units with hydrocarbon potential including the Evie Formation in British Columbia, the Keg River Formation in northern Alberta, and the Winnipegosis Formation in east-central Alberta and southern Saskatchewan. Many of these are proven source rocks of oils occurring in Middle Devonian reservoirs. Elk Point Group potential source rocks contain a wide variety of organic matter types reflecting the diversity of their depositional environments. No hydrocarbons have been definitively linked to a Beaverhill Lake Group source rock but it is possible that such a unit is the source of Slave Point Formation reservoired oils in northwest Alberta. The Late Devonian Woodbend Group contains the Duvernay Formation, the most prolific Devonian source rock in the Alberta Basin. It is characterized by marine Type II/I organic matter with TOC contents up to 15% in immature samples and is the source of most oils in the Bashaw Reef Complex, the Rimbey-Meadowbrook Reef Trend, and in the Swan Hills Formation in Alberta. The stratigraphically equivalent Muskwa Formation in northern Alberta has a much lower hydrocarbon potential than the Duvernay Formation. Oils have been correlated to Winterburn Group source rocks within the Nisku Formation of east-central Alberta, Camrose Member/Nisku Formation of southern Alberta, and the time-equivalent Birdbear Formation of southeast Saskatchewan. Winterburn Group potential source rocks in central to southern Alberta can have high TOC contents (up to 15%) and contain Type I and Type II organic matter deposited in open marine to lagoonal palaeoenvironments. The Cynthia Member shale of the Nisku Formation in west-central Alberta, previously thought by some workers to be a source rock, is actually organic-lean. The underlying Bigoray Member is more organic-rich and may be a minor contributor to hydrocarbons in the West Pembina area. The Wabamun Group contains no regionally extensive potential source rocks. Almost all the oil generated from Devonian source rocks appears to have remained within Devonian-aged reservoirs and very little is biodegraded. In contrast, where Exshaw Formation sourced oil is found in Devonian reservoirs, such as in the Grosmont and Nisku formations in the vicinity of the Athabasca Mannville Group bitumen deposit (i.e. “Carbonate Trend”), it tends to be biodegraded. You do not have access to this content, please speak to your institutional administrator if you feel you should have access.

A Laboratory Study on Near-Miscible CO2 Injection in Steelman Reservoir

Abstract Miscible flooding is considered unsuitable for some reservoirs in southeast Saskatchewan because of high C)2 minimum miscibility pressure or operating pressure constraints. Therefore, the effectiveness of near-miscible C)2 injection was assessed for the Steelman reservoir in a laboratory study. The minimum miscibility pressures (MMP) were estimated for Steelman reservoir fluids with pure C)2 and C)2-hydrocarbon gas mixtures, the partially flashed reservoir fluids and the dead oils with pure C)2. The results of MMP studies demonstrated (1) addition of ethane or propane can reduce C)2 MMP greatly; and (2) achieving a miscible C)2 flood in the Steelman reservoir could be possible at a lower operating pressure than the measured C)2 MMP, by partially depleting the reservoir. Asphaltene flocculation tests showed that, after the onset point, flocculation increased linearly with gas concentration, but that the presence of brine had a negligible effect. Three tertiary C)2 coreflood tests were conducted with Steelman reservoir fluids at the reservoir temperature. These results showed that the microscopic displacement efficiency during the C)2 injection stage improved with the operating pressure in the near-miscible region, but no dramatic change in oil recovery was observed with a change in operating pressure. Introduction The Steelman pool, located about 200 km southeast of Regina, Saskatchewan, was discovered in 1954. Covering approximately 370 km2, the field was estimated to contain over 134 million m3 of light oil in the Frobisher and Midale beds located at a depth of about 1,400 m. Most of the reservoirs in the Midale beds, which contain about 83﹪ of the reserves of the pool, have been under waterflood for over 20 years and have nearly reached the estimated production limit by primary and waterflood(1). For achieving additional oil recovery and consequent financial benefits, the development of tertiary enhanced oil recovery (EOR) techniques, such as C)2 flooding, is essential. Miscible C)2 flooding is a proven enhanced oil recovery technique(2). Over the last decade, C)2 injection has become the leading EOR process for light oil(3). In Canada, the industry interest in C)2 flooding is evidenced by Shell Canada's C)2 pilot tests(4, 5), a miscible C)2 flood at Joffre field in Alberta(6), and the implementation of PanCanadian's Weyburn C)2 injection project(7). Additional field applications are expected to be initiated in southeast Saskatchewan and other regions when C)2 sources are available. Miscible C)2 displacement offers the greatest oil recovery potential, but it can only be achieved at a pressure greater than a certain minimum referred to as the minimum miscibility pressure (MMP). The effect of solution gas on the development of miscibility is not well understood, as is reflected by the lack of a consensus in the literature. Rathmell et al.(8) found that C)2 MMP is related to the volatile and intermediate fractions of the oil. Yelling and Metcalfe(9) found from their experimental study that, for a saturated reservoir oil, areal variation in gas-oil ratio (GOR) will result in an areal variation in the C)2 MMP. They pointed out that the C)2 MMP determined for a pilot area may not apply to the rest of the field.

Persistence of cattle grubs (Diptera: Oestridae) on a Canadian ranch with long-term, continuous therapeutic control

Sero-prevalence of cattle grubs (Diptera: Oestridae) was monitored on two large western Canadian ranches from 1992 to 1999. One ranch has had a long-term programme for therapeutic control of cattle grubs as required by legislation in the province of Alberta. The other ranch, located in southeast Saskatchewan, has not used any treatment for grub control for an extended period of time. Serum from calves was tested each fall for the presence of antibodies to Hypoderma spp. using an ELISA. Percent positive sera on the Ranch 1 ranged from 8.0 to 73.3%. There was substantial variation among years and among two separate herds maintained on the ranch. Percent infested calves on the Ranch 2 ranged from 76.5 to 99.0%. Improved surveillance for cattle grubs using serological techniques is the only effective means to monitor the status of this important parasite.

Effect of Solution Gas in Oil on CO2 Minimum Miscibility Pressure

Abstract In this study, a rising bubble apparatus (RBA) was used to determine the CO2 MMP for various oils. RBA tests permit direct observation of changes in bubble behaviour and thus offered insight into the phase behaviour for the CO2-reservoir fluid system. The CO2 MMPs were estimated for two Steelman reservoir fluids with a high gas-oil ratio, the partially flashed reservoir fluids, and the dead oils. The composition of solution gas of each partially flashed reservoir fluid was determined and the effects of different gas components were analysed. The MMP was also determined and discussed for Weyburn reservoir fluids which had a low gas-oil ratio with pure and impure CO2. The results of this study demonstrated that the effect of solution gas in oil on CO2 MP could be significant. Furthermore, achieving a miscible CO2 flood (in a reservoir with a Steelman-like reservoir fluid) could be possible at a lower operating pressure than the measured CO2 MMP, by partially depleting the reservoir. This may be the only option for some reservoirs which cannot sustain the relatively high pressure required for achieving miscibility. Introduction Carbon dioxide flooding is a proven oil recovery process(1). Over the last decade, carbon dioxide injection has become the leading enhanced oil recovery (EOR) process for light oils(2). CO2 injection can prolong, by 15 to 20 years, the production life of light oil fields nearing depletion under waterflood, and may recover 15 to 25% of the original oil in place. More than 20 years of field experience of CO2 injection has advanced the CO2 technology. CO2 injection can be introduced gradually and use some of the same equipment currently in place for waterflooding. Saskatchewan's light and medium oil resource, representing nearly 45% of proven reserves, has been on waterflood for over 30 years and is fast approaching its economic limit of production(3). For the light and medium oil reservoirs in Saskatchewan, carbon dioxide or hydrocarbon injection is considered to be the most effective EOR process(4–6). These gases can be injected into the reservoir to develop miscible or immiscible conditions with the oil depending upon the operating pressure. Carbon dioxide is preferred over hydrocarbon gases (e.g., ethane, propane) because it is cheaper, has higher density, and offers environmental benefits by providing storage for CO2 in the reservoir. The Saskatchewan Research Council (SRC) is conducting a comprehensive research program to assess the suitability of miscible CO2 displacement for reservoirs in southeast Saskatchewan and to optimize the field operating procedures. The first step in determining if a field is a viable CO2 flood candidate is to conduct a screening study to provide a reasonable estimate of CO2 injection performance. The minimum miscibility pressure (MMP) is a key parameter used in the assessment. It has been recognized that the CO2 MMP for a reservoir oil depends on the reservoir temperature, oil composition, and the purity of injected CO2. The minimum miscibility pressure increases with increasing reservoir temperature.

Laboratory Investigation of Weyburn CO2 Miscible Flooding

Abstract Weyburn reservoir, located in southeast Saskatchewan and operated by PanCanadian Petroleum Ltd., has reached its economic limit of production by waterflooding. The reservoir is a target for tertiary CO2 miscible flooding to enhance oil recovery and extend its production life. A comprehensive study has been conducted by the Saskatchewan Research Council and PanCanadian to assess the suitability of the process for Weyburn. This paper presents a technical evaluation of CO2 near-miscible injection for Weyburn reservoir. This is based on laboratory studies conducted with three Weyburn oils collected from different regions of the reservoir. These studies included:measurement of minimum miscibility pressure for the reconstituted reservoir fluids for pure and impure CO2,determination of PVT properties for reservoir fluid-CO2 mixtures, andassessment of recovery behavior from uniquely designed laboratory core-flood tests representing the permeability contrast of the reservoir. The studies indicated that the CO2 minimum miscibility pressure for the Weyburn reservoir oils varied from about 11.5 to 14.5 MPa, indicating suitability for CO2 miscible flooding. PVT data generated for the three Weyburn reservoir fluid-CO2 mixtures showed that viscosity reduction and oil swelling by CO2 also contributed to oil recovery. A slight manipulation of the measured PVT properties of the mixtures made it possible to obtain single property curves for the three Weyburn oils. This feature can be used to estimate the PVT behavior for any Weyburn oil from the reservoir. Core-flood studies showed that CO2 injected into the Vuggy zone could rise to the upper Marly zone and help enhance oil recovery. A separate simulation and modelling study conducted by PanCanadian Petroleum Ltd. satisfactorily matched the experimental PVT properties, MMP values and recovery mechanism suggested by the core-flood behaviour. Introduction The total oil reserves of Saskatchewan are estimated at over 3 billion m3 of initial oil-in-place (IOIP). The light and medium oil reserves contribute approximately 1.6 billion m3 IOIP(1). Over 10﹪ of the light and medium reserves, or 178 million m3 IOIP, are held in Weyburn reservoir. The Weyburn field is located approximately 130 km southeast of Regina in Saskatchewan and covers over 180 km2 of production area. The field was discovered in 1955 and PanCanadian Petroleum (PCP) Ltd. is the major operator. It has over 627 producing wells and 162 water injection wells on approximately 24 ha spacing(2). The oil production from the Weyburn field comes from Midale beds of the Mississippian Charles Formation in the Williston Basin at a depth of 1,310 to 1,500 m. The field was produced by primary depletion for about nine years until 1964. Waterflood was started thereafter using a nine-spot pattern. In 1985, to optimize the waterflood performance, both horizontal and vertical infill drilling programs were initiated. The combined oil recovery by primary and secondary production was approximately 28﹪ IOIP by 1994. Waterflooding has almost reached its economic limit for the Weyburn reservoir. The ultimate conventional recovery is expected to be 31﹪ IOIP, leaving a large target for tertiary recovery techniques(3). A similar situation exists for the majority of Saskatchewan's light and medium reservoirs(1,4).

Abstract: Characterization of Mississippian Midale and Ratcliffe Reservoir Dolostones of Southeast Saskatchewan

Dolostones of Southeast Saskatchewan. Doug N. Harvey* (University of Regina) 3737 Wascana Parkway, Regina, Saskatchewan S4S 0A2, dnharvey@sk.sympatico.ca Dr. Donald M. Kent (University of Regina) Dr. Hairuo Qing (University of Regina) Dolomicrites constitute the major reservoir lithologies of the Midale and Ratcliffe Beds of southeastern Saskatchewan (Table 1 page 2). They are productive in the Benson, Glen Ewen, Oungre, and Hummingbird fields where they have been sampled as part of a dolostone reservoir characterization project that will cover dolomicrites in Mississippian, Devonian and Ordovician rocks (Figure 1).

Asphaltene Deposition During CO2 Flooding

SummaryIn this article we present results of dynamic and static precipitation tests to investigate the likelihood of asphaltene deposition problems in southeast Saskatchewan's Weyburn reservoir. Tests were conducted at the reservoir temperature and pressure conditions. The effect on asphaltene flocculation/precipitation of the operating pressure, CO2 concentration, gas contaminants in CO2, and presence of formation brine was investigated for three different oil samples using static pressure/volume/temperature (PVT) tests. The extent of asphaltene deposition was also assessed through coreflood experiments and through an x-ray computer- aided tomograph (CAT)-scanning visualization experiment.Static tests indicated the most important factor on which the asphaltene precipitation depended was the CO2 concentration. For oils belonging to the same pool, the increase in asphaltene precipitation with solvent concentration was proportional to the initial asphaltene contents of the oil. Coreflood experiments showed a considerable increase in asphaltene deposition in the core matrix following CO2 injection. Pore topography of the core matrix played an important role in the extent of CO2-induced asphaltene deposition. X-ray CAT-scanning tests depicted localized areas of asphaltene deposition along the length ofthe core, with significant deposition suspected to be occurring near the inlet of the core.

Improved Production Operating Efficiencies Through Automation

Abstract During 1994 – 1995, Wascana Energy Inc. implemented a supervisory control and data acquisition system.(SCADA) covering its entire southeast Saskatchewan operating area. This SCADA system was implemented to improve operating efficiencies by reducing operating costs and increasing production volumes. The system provided for remote monitoring and control of certain production facilities and wells. Wascana contracted an automation system integrator to assist in customizing. the graphical user interface and configuring the PC based computer system to communicate with various end devices in several fields. The master polling station and backup PC are located in Wascana's Estevan office. Data communications between the Estevan office, the field and district offices is accomplished with a UHF radio system and existing phone lines. Selected real time data is stored on an SQL database server, located on Wascana's local and wide area networks (LAN, WAN) to support corporate wide data sharing. Field automation includes wellhead managers (WHM) on all horizontal producers for pump off control and real time dynamometer analysis, remote tank level monitoring, electronic flow measurement, water injection facility control and flowline leak detection. Introduction In 1994, Wascana Energy (WEI) increased the focus on production automation as one means to improve operating performance, through reduced operating costs and increased production volumes. Published literature, personal project visits and discussions with other companies, active in automation, confirmed that opportunities existed for improving cost and production performance. Although Wascana already had several operations with field level automation (programmable logic controllers (PLCs) controlling a number of facilities, SCADA in a small number of gas fields and initial experience with pump off control for beampumped oil wells), a consistent area or corporate wide approach did not exist. Electronic flow measurement and remote monitoring andlor control were limited. Initial experience with wellhead managers (WHM) for pump off control (POC) began in 1993 on a horizontal well drilled by WEI in the Weyburn area of southeast Saskatchewan. Since that initial installation, WEI has installed WHMs on over 40 horizontal wells in the southeast area. These horizontal wells account for more than 50% of WEI production from southeast Saskatchewan. WHMs are now routinely installed on new wells and monitored by the SCADA system from the company's area office at Estevan. The initial SCADA system utilized during 1993/1994 consisted of VHF radio communications between several WHMs (horizontal wells) and Estevan using a basic, DOS-based, Graphical User Interface (GUI), provided by the WHM vendor. The radio communications was subsequently upgraded to UHF frequencies and a sophisticated, Windows-based, GUI was installed that includes a comprehensive voice callout and alarm system. Wellhead managers are polled directly from the Estevan control centre and other remote monitoring is accomplished via field level remote terminal units (RTUs) and PLCs. Other field level sensors, end devices and electronic flow measurement devices are tied into these field RTUs and PLCs. Although primary control is at the field level, the SCADA system can pass certain control commands from the control centre to the field RTUs.

Technical Feasibility of CO2 Flooding in Weyburn Reservoir - A Laboratory Investigation

Abstract Miscible or near-miscible flooding with CO2 or hydrocarbon gases will significantly increase, and extend the production life of, Saskatchewan light and medium oil reserves. These pools are approaching their economic limit of production under conventional technology (primary and secondary recovery methods). Responding to industry needs, a comprehensive study by Saskatchewan Research Council is assessing the suitability of the CO2 flooding process for reservoirs in southeast Saskatchewan. This paper presents the details of a laboratory study to evaluate the applicability of CO2 flooding for a southeast Saskatchewan reservoir, Weyburn. The evaluation is based on the measurement of CO2 minimum miscibility pressure for the Weyburn reservoir fluid, of PVT properties for reservoir fluid CO2 mixtures, and of oil recovery behaviour from core flood tests conducted in the near-miscible region. Laboratory studies showed that the tertiary CO2 injection at over 12 MPa into the waterflo'oded reservoir is expected to produce miscible flooding conditions. At this pressure of injection, over 60 mol % CO2 was dissolved in the reservoir fluid. This reduced the viscosity of the fluid nearly fourfold to 0.70 mPa.s and swelled the oil about 45%. Coreflood studies indicated that the microscopic displacement efficiency of the process increased with injection pressure in the near-miscible region. It is believed that the geology of the Weybum reservoir will prove advantageous for near-miscible operation. However, this aspect needs to be further investigated. Introduction Most of Saskatchewan's light and medium oil (LMO) reservoirs have reached their economic limit of production under conventional technology. Primary and secondary methods together recover about 21% of the initial oil-in-place (IOlP). Although the remaining light and medium oil-in-place in Saskatchewan is 1,373 million cubic metres(1) the remaining reserves producible under primary and secondary recovery are only 59 million cubic metres. This latter number would rise by 20 million cubic metres if medium oil in southwest Saskatchewan, not considered here, were included(1). The development of tertiary recovery techniques is, therefore, essential to increase the production life of these reservoirs and to maintain current production. Application of the miscible or near miscible oil displacement process using CO2, hydrocarbon or other gases as injection fluids is expected to increase the LMO reserves threefold and extend the production life of these pools by two decades(2). Miscible (or near-miscible) flooding with carbon dioxide or hydrocarbon solvents is considered to be one of the most effective enhanced oil recovery (EOR) processes applicable to LMO reservoirs. A comparison of effectiveness of CO2 and hydrocarbon gases as miscible solvents has been discussed(3). CO2 floods minimize gravity segregation compared with the hydrocarbon solvents. In addition, CO2 generally costs less than hydrocarbon miscible solvents in the United States(3). There is a limited supply of CO2 in Saskatchewan and Alberta for EOR purposes. However, CO2 can be imported from the U.S. to be implemented in miscible displacement projects in Canada. Current industry interest in CO2 miscible flooding is high, as evidenced by the growing level of activity in field testing(4) and increasing production from this method worldwide.

Quantification of Asphaltene Flocculation During Miscible CO2 Flooding in the Weyburn Reservoir

Abstract In a CO2 miscible displacement process, asphaltenes from the oil can flocculate in the presence of CO2 and can cause numerous production problems with a detrimental effect on oil recovery. A five-year multiclient research project was initiated in 1988 to evaluate the suitability of CO2 as an enhanced oil recovery (EOR) agent for a southeast Saskatchewan reservoir, Weyburn. The initial asphaltene content of the oils collected from the Weyburn pool was about 5% and suggested the possibility of formation plugging and wettability alteration during a CO2 injection. A laboratory study using a prototype high pressure PVT cell was undertaken to quantify asphaltene flocculation during a CO2 miscible flood in the Weyburn field. A photo metric technique was developed to determine the asphaltene content of the flashed CO2-saturated test oils. The effect on the asphaltene flocculation of operating pressure, CO2 oil contact; time, CO2 concentration, gas contaminants such as N2 and CH4' in CO2, and the presence of formation brine was investigated for; three different oil samples (approximately 29 ºAPI) collected from the pool. Results of the study indicated that asphaltene began to flocculate at about 42 mol% CO2 concentration. After this onset, there was a linear increase in asphaltene flocculation with CO2 concentration. The asphaltene flocculation pattern seemed to be, relatively insensitive to the operating pressure in the pressure range studied. The normalized asphaltene flocculation data showed a negligible effect of brine and contaminants in CO2 tested. For the experiments conducted in the single-phase region) the effect of CO2 oil contact time on asphaltene flocculation during the 4–19 day period was negligibly small. However, the mixing time required to achieve equilibrium in the two-phase' region was significant. Introduction The majority of the Saskatchewan light and medium oil (LMO) reservoirs have reached their economic limit of production under current technology (primary and secondary recovery methods)(1). Miscible flooding with carbon dioxide is shown to be a promising enhanced oil recovery (EOR) technique for southeast Saskatchewan reservoirs (2). Recent research suggests that near miscible (or extremely low interfacial tension) CO2 flooding can result in highly efficient displacement(2). A study(4) undertaken by Saskatchewan Energy and Mines has shown that the successful development of the miscible (or near-miscible) displacement process using CO2 and hydrocarbon gases can lead to a significant increase in Saskatchewan LMO reserves and substantially extend the production life of these pools. Crude oil normally consists of a conglomeration of waxes, resins, asphaltenes, and other semisolid materials. Because of their different physical and chemical characteristics, and when subjected to slight changes in equilibrium conditions, paraffins, resins and asphaltenes often precipitate. One of the problems confronting researchers and field operators is asphaltene deposition during a CO2 miscible flood. This concern with asphaltene deposition and problems arising from it during CO2 miscible flooding was one aspect of a comprehensive five-year multiclient research project(5). It was started in 1988 at the Saskatchewan Research Council (SRC) to evaluate the suitability of CO2 as an EOR agent for a southeast Saskatchewan reservoir, Weyburn.

Stratigraphy And Depositional Environments of the Bakken Formation (Upper DevonianILower Mississippian) In West-central Saskatchewan

Abstract The Upper Devonian/Lower Mississippian Bakken Formation of west-central Saskatchewan comprises three members: the lower black shale member (LBSH), the middle sandstone member and the upper black shale member (UBSH). Seven different facies have been defined in the middle sandstone member:oolitic bioclastic grainstone facies (OBG);lower bioturbated siltstone facies (LBS);thinly-bedded bioturbated sandstone facies (TBBS);thinly-bedded sandstone facies (TBS);interbedded sandstone-siltstone-shale facies (ISSS);upper bioturbated siltstone facies (UBS);transitional facies (CSST). The upper black shale member (UBSH) is a facies equivalent of facies six and seven in the middle member. During the early stages of deposition of the Bakken Formation, the basin waters were relatively deep and the lower Bakken shale member (LBSH) was deposited below storm wave-base under anoxic conditions. Shallowing before, or at the beginning of middle Bakken deposition resulted in the development of oolitic shoals (OBG) in a shallow, open marine setting and fine-gniined siliciclastic sediments (LBS) accumulated basinward of the shoals. Subsequent deepening of the basin waters was accompanied by progradation of terrigenous sediments. These were distributed and reworked by storms and tidal currents (TBS, TBBS and ISSS), ultimately burying the oolitic shoals. Late Middle Bakken deposition was marked by continued basin deepening with possible localized brackish or lagoonal conditions (CSST) and open marine offshore shelf conditions (UBS). With continued transgression, sediment supply was reduced and sediments remained in flooded river-valley systems. The upper Bakken shale member represents basin deepening coincidental with transgression, sediment starvation and a return to anoxic marine conditions (UBSH) similar to, but less widespread than those of the lower Bakken shale. Introduction The Upper Devonian/Lower Mississippian Bakken Formation is a predominantly siliciclastic, marine unit in the subsurface of the Williston Basin and parts of southeastern Alberta. In west-central Saskatchewan the Bakken Formation varies from 0 to more than 31 m thick. The original depositional thickness commonly is not represented as a result of sub-Cretaceous erosion. In the study area. Bakken strata unconformably overlie the Big Valley Formation. They are unconformably (locally conformably?) overlain by the Lodgepole Formation, or are unconformably overlain by Cretaceous sands or the Success Formation (JurassicCretaceous?). The Bakken Formation has long been a useful marker unit because of its distinctive log signature. Recently, oil has been successfully recovered from the formation by horizontal drilling(1). Oil is produced in southeast and west-central Saskatchewan, the area of this study (Figure 1), and in southwest Manitoba. The Bakken Formation has been subdivided into three informal Member (2), all of which are recognized where the Bakken has been identified. They are the Lower black shake member, the middle sandstone member, and the upper black shale member (Figure 2). The purpose of this paper is to describe the Bakken facies and associated rock-types in west-central Saskatchewan (Figure 1) using evidence from the study of about 50 cores and associated well-log data, and to make a preliminary interpretation of the depositional history of the formation in the study area.

A Laboratory Miscible Displacement Study For the Recovery of Saskatchewan's Crude Oil

Abstract Most of Saskatchewan's light and medium oil (LMO) reservoirs have reached their economic limits of production under waterflooding, leaving 70 to 80 per cent of the initial oil-in-place (IOIP) in the reservoirs. The miscible displacement process using carbon dioxide, hydrocarbon, and other gases as solvents appears to be one of the most promising methods for these reservoirs. A laboratory study was conducted to evaluate the applicability of various solvents for the recovery of oil from a southeast Saskatchewan reservoir. The physical, chemical, and phase behavior (PVT) properties of wellhead and reservoir fluids were determined. Slim tube displacement tests were conducted between the reconstituted Pinto reservoir fluid and three solvents: carbon dioxide, ethane, and wellhead gas from the Steelman gas plant. Tests were carried out at various pressures and the reservoir temperature of 56 °C. The minimum miscibility pressures (MMPs) determined for the above three systems demonstrated that the MMP for ethane was much lower than that for carbon dioxide, which was lower than that for Steelman gas. The MMPs for ethane and carbon dioxide were below the reservoir fracture pressure. Introduction Most of Saskatchewan's light and medium oil (LMO) reservoirs have reached their economic limit of production under current technology. Primary and secondary methods together recover about 21 % of the initial oil-in-place (IOIP). Although the remaining light and medium oil-in-place in Saskatchewan is 1135 million cubic metres(1), the remaining producible reserves under primary and secondary recovery are only 65 million cubic metres. Medium oil in southwest Saskatchewan has not been considered here, but if it is included then up to 17 million cubic metres of additional oil (through primary and secondary recovery) may be recovered(1). The development of tertiary recovery techniques, therefore, is essential to increase the production life of these reservoirs and to maintain current production. Application of the miscible oil displacement process using CO2, hydrocarbon, or other gases as injection fluids is expected to increase the LMO reserves threefold and extend the production life of these pools by two decades(2). Miscible flooding with carbon dioxide or hydrocarbon solvents is considered to be one of the most effective enhanced oil recovery (EOR) processes applicable to LMO reservoirs. Current industry interest in CO2 miscible flooding is high, as evidenced by the level of activity in field testing(3,4) and CO2 source development in the United States. CO2 has a viscosity similar to hydrocarbon miscible solvents. Both types of solvent affect the volumetric sweep out because of unfavorable viscosity ratio. However, CO2 density is similar to that of oil. Therefore, CO2 floods minimize gravity segregation compared with the hydrocarbon solvents. In addition, the supply cost of CO2 is generally more favorable than hydrocarbon miscible solvents in the United States(3). However, there is no cheap source of CO2 in Canada yet. It should be noted that, since the world oil price collapse in 1986, the number of EOR projects in the United States has decreased markedly from 512 in 1986 to 366 in 1988, whereas the number of CO2 miscible projects has increased from 38 in 1986 to 49 in 1988, a 29% rise during these two years(4).