Reservoir Evaluation and Hydrocarbon Play Assessment of the Cardium Formation – Pembina FieldTownship 46-47 Range 7-8W5 EvaluationBrad Parkes, Luke Makowski, Mark Bilyk
Preface The Pembina field is a vast, world class oilfield located in west central Alberta. There has been a long history of drilling and production in this prolific after being discovered in 1953. Since that time several thousand wells have been drilled to delineate the field and over nine billion barrels of original oil in place resource has been mapped. Approximately only fourteen percent of this oil has been recovered to date primarily by primary production methods so there is a significant opportunity for enhanced oil recovery. Water flooding currently plays an important role in advanced recovery and to maintain reservoir pressures for the solution gas drive of the reservoir. With the advent of polymer flooding, horizontal wells, and multi stage fracturing the field is experiencing a second life with increased production levels reaching rates equivalent to nearly thirty five years ago.
The Upper Cretaceous Cardium Formation of the Colorado Group is the reservoir for the Pembina field. This reservoir is contained within a six hundred meter thick shale envelope and is stratigraphically trapped as the Cardium clastic wedge pinches out laterally into shales. The Pembina River zone of the Cardium Formation is a coarsening upward shallow shelf to shoreface sequence that was mapped for three horizons: lower sand, upper sand, and conglomerate. Each unit was mapped using appropriate cut-offs for net sand, net reservoir, net pay, and the porosity times net pay maps. These maps reveal linear sand bodies trending in a northwest to southeast across the study area. The thickest reservoir trends are concentrated in township 47-7W5 and these trends correspond with strong historical production. However in section 27-47-7W5 there is anomalously low production associated with some of the most attractive mapped reservoir trends. For these two reasons a long reach horizontal well is proposed for drilling across section 27 from a northwest to southeast perspective to encounter this bypassed pay.
Table of Contents
Original Oil In Place
Production History and Forecast
Conclusions and Recommendation
The objective of this study is to thoroughly evaluate the Pembina Cardium Field in a core study area of four townships in the southwestern margin of the pool. Key factors in the evaluation include the geologic setting, production history, and economic analysis. These combined factors will show the potential future upside of the field and whether or not to aggressively pursue attractive lands that contain high grade drilling targets within the study area.
The Pembina Cardium Field is Upper Cretaceous in age and consists of a siliciclastic sequence of shales, silts, sands, and conglomerate. Pembina is the largest conventional oilfield in Canada containing over nine billion barrels of high quality original oil in place (~40API). This world class field is located in west-central Alberta and covers over two thousand square kilometers. Figure 1 shows the Cardium Formation oil fields of west-central Alberta and the vast aerial extent of the Pembina Field is evident. The study area highlighted in Figure 1 encompasses four townships on the southwestern margin of the field.
Figure 1: Geological cross section of the Gregoire Lake area. Note the four township area of interest highlighted in red. Modified after: http://www.canadianoilstocks.ca/canadian-oil-stocks-top-5-cardium-oil-juniors/
The Pembina Cardium Field was discovered in 1953 and since then over seven thousand wells have been drilled to delineate the pool. There are over thirteen hundred wells in the study area alone leading to a wealth of information and ability to identify high grade targets. Despite over sixty years of production approximately only fourteen percent of the original oil in place has been produced. Figure C21(in Appendix) shows the long term steady decline of the pool, however in 2009, there is an abrupt rise in production attributed to the application of multi-stage fractured horizontal well technology that is revitalizing the ageing field.
Wells within the study area were interpreted and mapped for three reservoir units of the Cardium Formation that consisted of a lower sandstone, upper sandstone, and capping conglomerate unit. Applying appropriate cut-offs allowed for detailed net pay mapping that was ultimately used for volumetric estimates of in place and recoverable oil over the study area.
The Cardium Formation can be lithostratigraphically divided into the lower Pembina River Member and the upper Cardium Zone Member (Krause and Nelson, 1984) as shown in Figure 3.
Figure 3: Lithostratigraphic division of the Cardium Formation. Modified from Krause and Nelson, 1984.
The focus of the study was on the coarsening upward sequence of the Pembina River Member. As Figure 2 shows there is a coarsening upwards sequence from the base of the zone culminating in deposition of the lower sand reservoir. The fine grained lower sandstone ranges in thickness from zero to twelve meters using a 90 API cut-off and using a porosity cut-off of 12% the reservoir interval ranges from zero to four meters. (Figure A9 and A10 Appendix). The figures show bar type sand features that are interpreted to be characteristic of a shallow shelf environment There is an approximately 2 meter non-reservoir interval of siltstones dividing the lower sandstone from the upper sandstone that is interpreted to be a flooding event of the shallow shelf. After this flooding the fine grained upper sandstone was deposited. This upper sand ranges in thickness from zero to eight meters using a 90 API cut-off and using a 15% porosity cut-off the reservoir thickness ranges from zero to four meters (Figure A5 and A6 Appendix). The figures show this sand is deposited in much more linear bodies trending from the northwest to the southeast which are consistent with a shoreface environment. Immediately capping the upper sandstone reservoir is the conglomerate reservoir. The conglomerate is dominantly composed of chert pebbles and due to its overall clean nature the net pay and reservoir maps are identical (Figure A2 and A3 Appendix). The conglomerate net sand and reservoir maps also show linear bodies that also trend in the northwest to southeast direction (Figures A1 and A2 Appendix). Although the conglomerates cap the overall coarsening upwards sequence it is important to note that they are not genetically related to the coarsening upwards sequence (Plint et al, 1986). The conglomerates mark a transgressive system of erosion and have an unconformable base with the underlying upper sandstone.
The upper sandstone represents a continuous fine grained marine sandstone that extends over the entire Pembina region and can be seen in all cores (Krause and Nelson, 1984). The reservoir unit was deposited as an eastward prograding shoreface (Krause and Nelson, 1984). The lower sandstone is a thinner elongate shelf sandstone body trends NW-SE and is present in all our cores, but to the east that may not be true due to the thinning and truncation of the Pembina Member River (Krause and Nelson, 1984). The Pembina River Member transitions from a shelf to shoreface environment up the core.
Within the Pembina River Member there is one or more coarsening upward cycles representing the upper and lower sandstone deposition. The Cardium was deposited during a period of sea level oscillation with the lower and upper sandstones deposited during a period of sea level drop, or regression and the conglomerates were deposited in the subsequent transgression ending the Cardium Formation deposition (Krause and Nelson, 1984). The upper sandstone is separated from the overlying conglomerates by an erosional unconformity surface known as the E5 marker (Krause and Nelson, 1984).
These different depositional environments created a heterogeneous reservoir with anisotropic conditions. Permeability measures of Kmax, Kvert and K90 are not equivalent and average porosity values for the different reservoir units vary from 5% in the conglomerate to 15% in the upper sandstone (Figure D22 Appendix). The Cardium Formation has undergone less chemical compaction with less developed quartz overgrowths than similar formations creating an abnormal trend of depth with porosity, where anomalously high values of porosity can be found at depth (Thomas and Oliver 1979). This reservoir heterogeneity emphasizes the necessity of examining the porosity – net pay maps to identify areas of high porosity and net pay.
The Cardium Formation is a stratigraphically trapped reservoir. The formation has very little structural features and dips at less than one degree from NE to SW from 1200 meters in the NE to 1900 meters in the SW (Butrenchuk et al 1995). The reservoir at Pembina is one of the worlds largest stratigraphic traps, formed as the Cardium clastic wedge pinches out laterally into shales of the Colorado Group. The drive mechanism is a solution gas drive system and there is no gas cap and no water leg to pool, however five decades of water injection has induced a water front (Butrenchuk et al. 1995).
Original Oil In Place
The Cardium Pembina Pool is the largest oil pool in the Western Canada Sedimentary Basin on an Original Oil in Place measure. Government estimates, from the National Energy Board put the OOIP at 9.4 billion barrels of oil (NEB 2011). Other authors have suggested lower OOIP estimates, however, GeoScout offers a similar estimate of 9.3 billion barrels of Original Oil in Place. Within the four township study area a volumetric analysis was used to calculate an OOIP of 453.5 million barrels of oil. The volumetric approach uses a formula (OOIP = A*h*Φ*(1-Sw) with A= area, h=net pay thickness, Φ = porosity and Sw = water saturation) based on four factors to calculate the OOIP. Since some of these factors vary across the reservoir, a range of acceptable values was calculated using different parameters. One drawback of the volumetric calculation is that it assumes a constant reservoir thickness across the area being evaluated. To adjust for this drawback, we calculated a best case scenario and a worst case scenario. The best case scenario (maximum net pay across the three horizons and high average porosity) suggested a maximum of 250 million barrels of oil per township and the low case (minimum thickness and low average porosity) estimated 120 million barrels of oil per township. This range fit well with our four township calculation, as about half of Township 46, Range 8 is not within the pool boundaries, suggesting the 3.5 townships within the pool boundaries held about 130 million of barrels on average. The volumetric approach requires the pool to have a low dip angle and this requirement is satisfied. Another requirement to use the volumetric approach is an understanding of the location of the water/oil contact. The Cardium Formation at Pembina has a solution gas drive mechanism and no waterleg. The water that is produced is from fifty years of water injection. A solution gas drive mechanism has the risk of the reservoir pressure dropping below the bubble point, the level of pressure where the solution gas comes out of solution and interferes with oil production, turning an oil reservoir into a gas reservoir. To maintain pressure an immediate water flood is required to maintain pressure (Pedersen 2013). Over time this can create an artificial waterleg, but this does not affect the volumetric method as this waterleg acts more as a sweeping mechanism than an infiltration system that comprises the areal extent of the reservoir.
Production History and Forecast
The Pembina Cardium Pool is a prolific producer of oil and associated gas. Pembina was discovered in 1953 and large scale development began in the early 1960s. This long history of production has lead to a large number of wells being drilled. There is currently 7304 wells across the entire pool, with 5510 oil wells, 5389 are active, 1752 injection wells, 17 gas wells (only gas) and 25 listed as other. Of the 7304 wells, 1097 are horizontal. Over the four township study are 1386 wells with 980 oil wells and 406 water injection wells.
The Cardium Pembina Pool is currently producing approximately 1.9 million barrels of oil per month. In 1970, the Cardium at Pembina maxed out at 4.5 million barrels a month. The production from the field dropped as low as 600,000 barrels of oil per month in 2010, prior to the implementation of horizontal well programs and hydraulic fracturing completion techniques. This new technology has lead to the rebirth of the Cardium as a viable exploration play. The recovery rates for the Cardium Pembina field under primary recovery is 8% and for primary, secondary and waterflood recovery the recovery rate is 15% (Sandu 2012).
The Cardium Pembina Pool has a solution gas drive mechanism that requires a water injection program to maintain reservoir pressure. This has lead to 2.025 billion barrels of water production. The pool has also produced 1.32 billion barrels of oil and 1335 billion cubic feet of gas.
The Cardium Pembina Field came on production in the mid 1950s, but monthly data on GeoScout is only available from 1963. This provides fifty plus years of production data (Figure C19 and C20 Appendix). Using a production decline method, as a whole the field has declined in a linear fashion at 6.95% per year up to 2010 (4.5 million barrels per month in 1970 to 600,000 barrels of oil per month in 2009). However, due to new completion methods and the expanded use of horizontal wells, previously uneconomic unconventional reservoirs are now being targeted and breathing new life into the field and increasing production. The recent spike in production to 1.9 million barrels per month production has not produced enough data to determine if the decline rate has changed. Using a production decline method we created 4 estimates for cumulative production based on 3 linear decline rates and one harmonic decline curve (Figure C19 Appendix). In the worst case scenario, where production returns to the fifty year trend there is approximately 150 million barrels of oil (total 1.45 billion barrels in cumulative production) of future production before reaching the economic limit of 2 barrels of oil/day per well (approximately 440,000 barrels of oil per month). The harmonic and most likely linear decline scenario suggest that there is 200-250 million barrels of oil production before hitting the economic production limit (1.5-1.55 billion barrels of oil cumulative production). The best case scenario would see a linear decline from the spike in production to 1.9 million barrels per month and would add another 500 million barrels of oil in cumulative production prior to hitting the economic limit (1.8 billion barrel of oil cumulative production). This upside in future cumulative production is one reason why Cardium Pembina play is a good exploration target. Another reason is the long reserve life. Plotting the monthly production on the Y axis in logarithmic form and time in months on the X axis (Figure C20 Appendix) and using three linear decline curves the production decline method produces a worst case, most likely case and best case scenario. Under the worst case scenario there is 120 months (10 years) of production left before reaching the economic limit of 440,000 barrels of oil per month. Under the most likely scenario there is 320 (23.3 years) months the best case scenario an additional 520 months (43.3 years) of production before dropping below the economic limit.
The remaining reserves present in the Pembina pool were calculated using the Prospect Decline Calculation worksheet developed by Chris Zinkan (Red Zed Energy Corp.). This method utilizes well log determined parameters of area, pay, porosity, water saturation, shale content, shape correction, and oil recovery factor. Oil recovery factor was determined using primary and secondary recovery, as well as water flood. Each member of interest within the Cardium (conglomerate, upper sandstone, and lower sandstone) had its reserves calculated on a section basis using differing parameters depending on the member. The conglomerate member was calculated using the parameters 5% porosity, 15% water saturation, 0% shale content, and a 15% recovery factor. The upper sandstone member (Sandstone A) was calculated using 15% porosity, 15% water saturation, 15% shale content, and a 15% recovery factor. The lower sandstone member (Sandstone B) was calculated using 12% porosity, 15% water saturation, 15% shale content, and a 15% recovery factor. The remaining reserves is shown in Figure 3.
Figure 3: Cardium formation OOIP by township. Note: Oil Saturation =85% Recovery Rate =15%
The remaining recoverable reserves are highest in the northern two townships within the area of interest at 26.51x106 barrels in 047-07W5 and 19.08x106 barrels in 047-08W5. The southern two townships contain 16.00x106 barrels in 046-07W5 and 6.43x106 barrels in 046-08W5, brining the total recoverable reserves present within the area of interest to 68.02x106 barrels of oil. The parameters utilized in Chris Zinkan’s Prospect Decline Calculation worksheet are suitable for estimating remaining reserves, however more parameters are needed for a more accurate estimation utilizing modern extraction techniques. GeoScout Pool ticket states the remaining reserves within the Pembina to be 1.385x109 barrels of oil. Our calculations show that our area of interest comprises 4.8% of the total recoverable reserves present in the field.
An estimation of the total ultimate reserves for the Pembina Field can be seen in Figure C19 (Appendix). This figure has Monthly Production versus Cumulative Oil Production as well as four ultimate reserve estimations (Worst Case scenario, Harmonic, Most likely, and Best case) before reaching the economic limit of 440,000 barrels a month. The ultimate reserve lines show that the worst case scenario ultimate recovery result in 1.45 billion barrels, harmonic decline would result in 1.5 billion barrels, best case would result in 1.8 billion barrels. The most likely estimation line in Figure C19 (Appendix) results in 1.55 billion barrels of ultimate reserves before reaching the economic limit. The recovery rates for the Cardium Pembina field under primary recovery is 8% and for primary, secondary and waterflood recovery the ultimate recovery rate is 15% (Sandu 2012).
There is good future potential for the Cardium formation in the Pembina field. The estimated oil production 200 to 250 million barrels of remaining production and a best case scenario of 500 million barrels of remaining production. The remaining reserve life for the field is estimated to be 10 years to 43.3 years with most likely reserve life of 23.3 years of remaining production (Figure C20 Appendix). This upside in future cumulative production along with the remaining reserve life is one reason why the Cardium Pembina play is of interest. Township 47-7W5 is the most attractive from a geological and production perspective with high production and net pay values. We propose in 27-47-7W5 a horizontal well that will intersect the thickest net pay of the mapped horizons. The well will be parallel to strike to intersect the prograding shoreface body. The well will have a surface location in 13-27-47-7W5 and travel to ~1550 meters total vertical depth, then start traveling horizontal in 11-27-47-7W5 for ~1700 meters to total depth in 1-27-47-7W5. The location of the proposed well is in an area of anomalously low production with wells of very high production near by. Figure C23 (Appendix) shows the log monthly rate of production versus time for well 4-26-47-7W5. This well is near in proximity to the proposed well location, and is the best producing well in the area of interest. Well 4-26-47-7W5 had a decline rate of 18% over 44 years. In 1997 the production decline rate became almost zero with relatively consistent production of 200,000 barrels/month since. Figure C24 (Appendix) shows well 4-26-47-7W5 monthly production rate versus cumulative production. This figure shows that currently this well has produced ~ 614,000 barrels of oil. With the current decline rate of this well, and future potential production of 23 years, we suspect that there is ~5.458x107 barrels of oil of future production remaining. The proposed well location of 13-27-47-7W5 should produce similar to that of 4-26-47-7W5. The proposed well will have a solution gas drive mechanism that requires a water injection program to maintain reservoir pressure. There is no gas cap and no water leg in proposed well site or pool (Butrenchuk et al. 1995).
Conclusions and Recommendation
The Pembina field is a vast, world class oilfield located in west central Alberta. Approximately only fourteen percent of this oil has been recovered to date primarily by primary production methods so there is a significant opportunity for enhanced oil recovery. Within the four township study area (Townships 46-47, Ranges 7-8) we used a volumetric analysis approach to calculate an OOIP of 453.5 million barrels of oil suggesting the 3.5 townships within the pool boundaries held about 130 million of barrels on average. The Cardium Pembina Pool is currently producing approximately 1.9 million barrels of oil per month. The recovery rates for the Cardium Pembina field under primary recovery is 8% and for primary, secondary and waterflood recovery the recovery rate is 15% (Sandu 2012). This has lead to 2.025 billion barrels of water in production, 1.32 billion barrels of oil and 1335 billion cubic feet of gas. There is approximately 250 million barrels of oil (total 1.55 billion barrels in cumulative production) of future production before reaching the economic limit of 2 barrels of oil/day per well (approximately 440,000 barrels of oil per month), with approximately 320 remaining months of production.
The remaining recoverable reserves are highest in the northern two townships within the area of interest at 26.51x106 barrels in 047-07W5 and 19.08x106 barrels in 047-08W5. Township 47-7W5 is the most attractive from a geological and production perspective with high production and net pay values. We propose in 27-47-7W5 a horizontal well that will intersect the thickest net pay of the mapped horizons. The well will be parallel to strike to intersect the progradation shoreface body. The well will have a surface location in 13-27-47-7W5 and travel to ~1550 meters total vertical depth, then start traveling horizontal in 11-27-47-7W5 for ~1700 meters to total depth in 1-27-47-7W5. The location of the proposed well is in an area of anomalously low production with wells of very high production near by. Using acquisition metrics published by Sayer Energy Advisors, the median price for a boe (barrel of oil equivalent) in the ground in the WCSB is ~12.00/boe and the median price paid for a flowing barrel of oil is $57,000/boe. The Cardium obtains an above median valuation, using $15.00/boe and 177,000,000 barrels of OOIP in township 47-R7W5 we estimate there is 4.9 million barrels of OOIP per section the value per section would be about $73,750,000, with 4 wells per section a single well or LSD would have an enterprise value of $18,500,000. Using an alternative method to calculate the enterprise value, using $75,000 per flowing boe (Sayer Advisors 2010 and Jason White – energy analyst at Junior Oil and Gas Capital Ltd personal communication April 21 2103) and the average IP30 of 250boe (Bonnavista Energy Report April 2013) the valuation becomes $75,000*250boe/d, the enterprise value is equal to 18,750,000 per LSD. Both calculations come to a similar value per LSD of $18.5 – 18.75 million per LSD. Enterprise value does not account for capital costs or the time value of money, so this figure needs to be converted to a Net Present Value. Using the minimum and maximum cost for a horizontal in the area of $2.5-4 million per well, an oil price of $90/bbl and $3/GJ gas, a first year decline rate of 50% and 18% each subsequent year over a 7 year time period the Net Present Value (discounted at 10%) of the cash flow indicates the amount we would be willing to spend would range between $14 - 15.6 million per LSD. We would be willing to purchase more land if the offering price was below the upper number in this range.
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Appendix (not included)
MapsFigure A1 – Conglomerate Net SandFigure
A2 – Conglomerate Net ReservoirFigure
A3 – Conglomerate Net PayFigure
A4 – Conglomerate Phi*hFigure
A5 – Upper Sandstone Net SandFigure
A6 – Upper Sandstone Net ReservoirFigure
A7 – Upper Sandstone Net PayFigure
A8 – Upper Sandstone Phi*hFigure
A9 – Lower Sandstone Net SandFigure
A10 – Lower Sandstone Net ReservoirFigure
A11 – Lower Sandstone Net PayFigure
A12 – Lower Sandstone Phi*hFigure
A13 – Reservoir Tops MapArea MapsFigure
B14 – Base Map with Pool OutlineFigure
B15 – Base Map with Cored Well IntervalFigure
B16 – Infrastructure MapFigure
B17a – Cross Section LineFigure
B17b – Cross SectionFigure
B18a – Production Map - OilFigure
B18b – Production Map – GasFigure
B18c – Production Map – WaterFigure
B18d – Production Map – Oil, Gas and Water Production GraphsFigure
C19 – Monthly Production vs. Cumulative Production GraphFigure
C20 – Monthly Production vs. Time GraphFigure
C21 – Cumulative Pool Production Map – Oil, Gas and WaterFigure
C22 – OOIP by Township ChartFigure
C23 – 4-26-47-7W5 Log Monthly Rate vs. Time GraphFigure
C24 – 4-26-47-7W5 Monthly Rate vs. Cumulative Production GraphOtherFigure
D22 - Porosity Cross PlotFigure
D23 – Type Log CalculationsOOIP per township range from GeoScout Pool ticket
OOIP = (bbl per acre*ft)*(net pay thickness (t))*(area (a))
GeoScout lists the OOIP as 646.6 bbl/acre*ft
Township has 23,040 square acres
Net Pay thickness – best case = 7m or 23 ft
Net Pay thickness – low case = 2.5m or 8ft
Best case = 250,000,000 OOIP per township
Low case = 120,000,000 OOIP per township
Enterprise Value using Metrics reported by Sayer Energy Advisors on transactions in WCSB$75,000/flowing boe*250 boe = $18,750,000
$15.00 boe in the ground OOIP * 177,000,000 OOIP in 47,08W5/36 sections = $73,750,000/4 wells per section = $18,437,500 per LSD
Discount rate 10%
Horizontal Well cost $2.5 - $4 million per well
7 year well life