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Naturally Fractured Reservoirs

Technical Notes

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Technical Note # 11. May 25, 2003

Net Pay in Naturally Fractured Reservoirs

By Dr. Roberto Aguilera.

Net pay is typically characterized by high porosity, high permeability and high hydrocarbon saturation. Cutoffs are used for defining the net pay. This note has to do with naturally fractured reservoirs (nfr's) where sometimes intervals with low porosity and low permeability, which do not meet conventional cutoff criteria, can constitute net pay. This note was published originally in CSPG Reservoir (June 2003).

It has been found through selective perforating, production logs, and rock mechanics experiments in cores, that for the same physical environment and stresses, other things being equal, the amount of natural fracturing increases as porosity and permeability of the host rock decreases. This is turn leads to the recommendation, that unless there is supporting information to the contrary, it is better not to use porosity and permeability as cutoff criteria in nfr's. The message is not that we should forget about intervals with high porosities and permeabilities. The message is that we should never overlook low permeability and low porosity intervals in nfr's.

In a "conventional" unfractured reservoir, the rock must be capable of allowing direct hydrocarbon flow into the wellbore to constitute net pay. In nfr's the rock, usually called matrix by reservoir engineers, does not have to necessarily permit direct hydrocarbon flow into the wellbore to constitute net pay.

Darcy's law indicates that fluid rate is equal to permeability times area times pressure differential divided by fluid viscosity and distance. The reservoir area exposed to the wellbore is typically very small. That small area times a small permeability does not allow enough hydrocarbon flow into the wellbore. If there is natural fracturing around the wellbore that extends throughout a large portion of the reservoir, the matrix area exposed to the fractures can become quite significant. In this case the product of the large area times the small permeability can allow very efficient hydrocarbon flow from matrix to fractures and then to the wellbore, constituting what is usually known as a dual porosity reservoir.

Aguilera and Aguilera (2001) have presented the schematic of a production log that shows only two zones where fluids enter the wellbore. However, the whole section from top to bottom is net pay.

If porosity and permeability are not advisable in many cases as cutoff criteria, how can we estimate net pay in a nfr from wellbore data?

In my experience, water saturation, shaliness and pore throat aperture, and keeping an eye on well testing data provide reasonable criteria.

I have used many times water saturation cutoffs in the order of 55%, although there are exceptions. When calculating Sw keep in mind that the dual porosity exponent m of the fractured intervals is smaller than the porosity exponent mb of only the matrix as determined from unfractured plugs. Be also careful with the scaling of matrix porosity to avoid potential errors in the calculation of Sw (Aguilera and Aguilera, 2003). The larger the amount of natural fracturing, the smaller the value of m. A useful assumption is that the required water saturation exponent n is approximately equal to m.

Shaliness is also a very important cutoff criterion. As plasticity increases there are less probabilities of finding fractures. Therefore Vshale is very valuable for determining net pay in nfr's. The variability of Vshale as a cutoff can be quite significant from reservoir to reservoir. For example, there are reservoirs where fractured shales produce at commercial oil and gas rates.

Pore throat apertures of the matrix can be estimated from mercury injection capillary pressures. If not available, there are empirical correlations that can help in the determination of the pore throat apertures. Particularly useful are the Winland r35 pore throat aperture explained by Martin et al (1997), and the rp35 radii than can be superposed directly on Pickett plots (Aguilera, 2002). Martin et al. (1997) provide potential oil rates that can be obtained from different pore throat sizes.

Well testing data can help, under favorable conditions, to determine via the "valley" generated by the pressure derivative, if the tight matrix is contributing production to the fractures (not to the wellbore). Also a derivative with a negative slope of 0.5 might indicate that fractures not intersected by the wellbore could be contributing to production.

It is not an easy problem. But I hope the guidelines presented above will help you in estimating net pay in your nfr's.

REFERENCES

1. Aguilera, R. and Aguilera, M. S.: "Well Test Analysis of Multi-Layered Naturally Fractured Reservoirs with Variable Thickness and Variable Fracture Spacing," Journal of Canadian Petroleum Technology (December 2001), p. 9-12.

2. Aguilera, R.: "Incorporating Capillary Pressure, Pore Throat Aperture Radii, Height Above Free Water Table, and Winland r35 Values on Pickett Plots," AAPG Bulletin (April 2002), p. 605-624.

3. Aguilera, R.: "Determination of Matrix Flow Units in Naturally Fractured Reservoirs," paper 2002-157 presented at the Petroleum Society Canadian International Petroleum Conference held in Calgary, Canada (June 11-13, 2002).

4. Aguilera, R. and Aguilera, M. S.: "Improved Models for Petrophysical Analysis of Dual Porosity Reservoirs," Petrophysics (January-February 2003).

5. Etris, Ned and Stewart, Bruce: "Net-To-Gross Ratio," CSPG Reservoir (April 2003), p.24-25.

6. Martin, A. J., Solomon, S. T. and Hartmann, D. J.: "Characterization of Petrophysical Flow Units in Carbonate Reservoirs," AAPG Bulletin (May 1997), p. 734-759.

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Technical Note # 10. December 28, 2001

Recognizing Natural Fractures not Intersected by the Wellbore

By Dr. Roberto Aguilera

Many times we are faced with the question: Are there any natural fractures that were not intersected by the wellbore, yet contribute to oil and gas (or water) production? The question stems from the observation of production logs that indicate that out of 100 ft perforated in a fracture reservoir maybe only 5 to 10 ft might contribute to production. Are the 5 to 10 ft the only pay in the reservoir? Or is there additional fracture pay not shown by the production log?

This problem was investigated in the past using a static model (reference 2) based on outcrop data published originally by Narr and Lerche (1984). The model allows estimating the distance between vertical parallel fractures based on core data. Depending on the fracture spacing, it is very easy for a vertical well to miss the vertical fractures. This has been observed in practice many times.

A numerical simulator and a gas well were used to investigate this problem (Aguilera, 2000) from a dynamic point of view. The initial model consisted of 10 layers. Each layer had different fracture permeability. The permeabilities were arranged in ascending and descending order, and also randomly. The geometric mean permeability of all layers was 40 md. Each layer had the same thickness (5.3 ft). Fracture spacing was constant (11 ft). Matrix porosity was 4.8%. Fracture porosity 0.5%. Gas saturation in the matrix was 58%. Gas saturation in the fractures was 100%.

Several drawdowns and buildups were run, which led to the conclusion that under favorable conditions it was possible to determine if there were fractures not intersected by the wellbore that were contributing to production. In this case the pressure derivative indicated partial penetration effects (a straight line with a negative slope equal to 0.5) even if the whole interval was open to production.

In addition to the simulated cases shown in reference 3, Aguilera and Aguilera (2001) have presented a case history of a fracture basement gas reservoir in Argentina. The slope of the derivative shows partial completion effects although the well was completed open hole. This suggests that fractures not intersected by the wellbore were contributing to production. An alternate interpretation is that the fracture pay of the basement reservoir extends below the TD of the well.

A 10-layer simulation model including layers with variable thickness and variable fracture spacing was considered in reference 4. In this case the partial completion effect was not evident and the pressure derivative presented similar characteristics to those observed in single-layer dual porosity models. The late part of the derivative gave a linear trend with a positive slope of approximately 0.5.

References

1. Narr, W. and Lerche, I.: "A Method for Estimating Subsurface Fracture density in Core", AAPG Bulletin (May 1984), p. 637-648.

2. Aguilera, R.: "Determination of Subsurface Distance Between Vertical Parallel Natural Fractures Based on Core Data", AAPG Bulletin (July 1988), p. 845-851.

3. Aguilera, R.: "Well Test Analysis of Multi-Layered Naturally Fractured Reservoirs", Journal of Canadian Petroleum Technology (July 2000), p. 31-37.

4. Aguilera, R. and Aguilera, M. S.: "Well Test Analysis of Multi-Layered Naturally Fractured Reservoirs with Variable Thickness and Variable Fracture Spacing", Journal of Canadian Petroleum Technology (December 2001), p. 9-12.

© 2001 Copyright by Servipetrol Ltd. All rights reserved.

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Technical Note # 9. September 22, 2000

Oil and Gas Recovery Factors in Naturally Fractured Reservoirs

By Dr. Roberto Aguilera

This is part of an article published by the author in the Journal of Canadian Petroleum Technology Distinguished Authors Series under the title "Recovery Factors and Reserves in Naturally Fractured Reservoirs" (July 1999).

In my opinion each naturally fractured reservoir should be considered as a research project by itself. As such, it has to be studied carefully and in detail to estimate recoveries.

There are instances where a recovery estimate is needed rather quickly for a preliminary evaluation.  The following table shows empirical oil recovery estimates as a percent of original oil-in-place. These estimates are based my experience with naturally fractured reservoirs. I have used them with some success in various naturally fractured reservoirs around the world. However, they are no panaceas. Use them carefully and only as order of magnitude indicators. There is no substitute for a detailed study.

Typical oil recoveries for naturally fractured reservoirs

Recovery Mechanism

Type A

Type B

Type C

Depletion Drive

10-20

20-30

30-35

Depletion Drive Plus Gas Injection

15-25

25-30

30-40

Depletion Drive Plus Water Injection

20-35

25-40

40-50

Depletion Drive Plus Water Inj plus Gas Inj

25-40

30-45

45-55

Gravity segregation with Counter-flow

40-50

50-60

>60

Depletion Drive Plus Water Drive

30-40

40-50

50-60

Depletion Drive Plus gas Cap

15-25

25-35

35-40

Depletion drive Plus Gas Cap Plus Water Drive

35-45

45-55

55-65

The following table shows empirical gas recovery estimates based on my experience as a percent of original gas-in-place:

Typical gas recoveries for naturally fractured reservoirs

Recovery Mechanism

Type A

Type B

Type C

Without Water Drive

70-80

80-90

>90

With Moderate Water Drive

50-60

60-70

70-80

With Moderate Water Drive and Compression

20-30

30-40

40-50

With Strong Water drive

15-25

25-35

35-45

The same classification of naturally fractured reservoirs from the point of view of storativity (Type A, B, C) was used in Technical Note # 7 in this series while discussing poor completions. In a reservoir of Type A there is high storage capacity in the matrix and low storage in the fractures. In a reservoir of Type B there is about equal storage capacity in matrix and fractures. In a reservoir of Type C all storage capacity is in fractures. For more details on this classification see reference 2, page 11.

References

1. Aguilera, Roberto: "Recovery Factors and Reserves in Naturally Fractured Reservoirs", Journal of Canadian Petroleum Technology, Distinguished Authors Series, July 1999, volume 38, no. 7, p. 15-18.

2. Aguilera, Roberto: Naturally Fractured Reservoirs, 2nd Edition, PennWell Books, Tulsa, Oklahoma (1995), p.11.

© 2000 Copyright by Servipetrol Ltd. All rights reserved.

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Technical Note # 8. November 23, 1999

Fracture Compressibility

By Dr. Roberto Aguilera

This is part of an article published by the author in the Journal of Canadian Petroleum Technology Distinguished Authors Series under the title "Recovery Factors and Reserves in Naturally Fractured Reservoirs" (July 1999).

Fracture compressibility is an elusive parameter. Let us consider 3 types of matrix/fracture interaction:

1) No Secondary Mineralization.- In this case we obtain good initial oil and/or gas production rates. However, is it good luck or just a teaser? When natural fractures are open and have a negligible amount of secondary mineralization the hydrocarbons move from the matrix to the fractures in an unrestricted way.

How quickly the fluids move from matrix to fractures is controlled by the amount of pressure drop in the fractures, matrix properties such as permeability, porosity and compressibility, viscosity of the fluid flowing, and fracture spacing or size of the matrix blocks. These fractures can provide very high initial rates.

The major problem with these types of fractures is that they might tend to close as the reservoir is depleted depending on the in situ stress, the initial reservoir pressure and the reduction in pressure within the fractures. In other words fractures are much more compressible than the host rock.

If the reservoir is initially overpressured the fracture closure can be very significant leading to small hydrocarbon recovery, big headaches and major financial losses.

If the reservoir is initially underpressured the fracture closure is not as significant because most of the closure at reservoir depth has already occurred. Ultimate recoveries will be bigger than in the previous case.

2) Some Secondary Mineralization.- I think good luck! When natural fractures have a certain amount of secondary mineralization the fluid flow from matrix to fractures is somewhat restricted. From the point of view of pressure behavior during well testing this can be visualized as a natural skin within the reservoir (not to be confused with mechanical skin around the wellbore routinely calculated).

Partial mineralization is a blessing in disguise. In this case the secondary minerals will act as a natural proppant agent and fracture closure will be significantly reduced (not completely stopped) even in overpressured reservoirs. This in turn will lead to higher ultimate recoveries. The fracture closure will be smaller in normally pressured reservoirs and even smaller in underpressured reservoirs.

3) Complete Secondary Mineralization.- Bad luck!! Even if there are a lot of hydrocarbons within the reservoir the ultimate recovery will be low. The mineralized fractures will compartmentalize the reservoir leading to very low ultimate recoveries.

Fracture Compressibility

As discussed above, open or partially mineralized fractures are more compressible than the host rock. Fracture compressibility is an elusive parameter. My recommendation is to determine this parameter in the laboratory using rocks (cores) from your own reservoir. If these are not available (and they are not available most of the time) we have to resort to empirical correlations.

I have estimated fracture compressibility throughout the years using a graph published in reference 1. I must emphasize, however, that this is only an approximation. The intent of the graph is not to replace good laboratory work. If you have laboratory data you can corroborate the validity or non-validity of the correlation for your reservoir. In the graph, MINER is the estimated percent mineralization and RATIO is equal to fracture porosity divided by the summation of fracture porosity and vuggy porosity.

In reservoirs where both matrix and fractures are present, it is possible to make an estimate of fracture compressibility based on knowledge of the percent of secondary mineralization within the fractures and the net stress on the fractures. For example, if the net stress on the fractures is 5,000 psi and the estimated secondary mineralization is 50%, then the compressibility from the graph is 26.3E-06 / psi. The graph presented in reference 1 includes net stress on fractures ranging between zero and 12,000 psi, and secondary mineralization ranging between zero and 50%.

In reservoirs where fractures and vugs are present it is possible to estimate their compressibility based on knowledge of net stress on fractures, fracture porosity and vuggy porosity. For example if the net stress on fractures is 6,300 psi and the ratio of fracture porosity divided by the summation of fracture porosity plus vuggy porosity is 50%, then the compressibility of the secondary porosity system is 1E-05 / psi from the correlation presented in reference 1. Ratios of fracture to total secondary porosity ranging between 10 and 90% are presented in Reference 1.

Measurements of in-situ stresses are very important. If they are not available, keep in mind when estimating fracture compressibility that in areas dominated by normal faulting the biggest stress is vertical and approximately equal to the net overburden. In this case the least stress is horizontal and approximately equal to one-half to one-third the net vertical stress.

In areas dominated by thrust faulting the biggest stress is horizontal and is approximately equal to two to three times the net overburden

References

1.      Aguilera, Roberto: "Recovery Factors and Reserves in Naturally Fractured Reservoirs", Journal of Canadian Petroleum Technology, Distinguished Authors Series, July 1999, volume 38, no. 7, p. 15-18.

© 1999 Copyright by Servipetrol Ltd. All rights reserved.


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Technical Note # 7. April 9, 1998

Pitfalls in Evaluation of Naturally Fractured Reservoirs

By Dr. Roberto Aguilera

This is summary of a presentation by the author at the Fracture Reservoirs Symposium organized by the Rocky Mountain Association of Geologists, Denver, Colorado, January 19 and 20, 1998. Three of the pitfalls discussed follow:

(1) Giving up after short periods of swabbing. A few hours of swabbing might not be enough in a naturally fractured reservoir. Many days are sometimes required specially if there have been significant mud losses. Cutting the swabbing time short might result in leaving behind as undiscovered a potentially commercial reservoir.

This was demonstrated at the meeting with data from a South American naturally fractured reservoir. Swabbing was conducted starting on February 3, 1996. Swabbing recoveries were as follows:

Feb 3: 431 bbls in 104 runs

Feb 4: 277 bbls in 93 runs

Feb 5: 291 bbls in 87 runs

Swabbing continued during Feb 6,7,8,9,10,11,12,13,14,15,16,17,18,19 recovering water and oil..... Talk about persistence. The effort eventually led to and oil production of 3500 BOPD from this well ... and a discovery!!! My recommendation again: Do not cut your swabbing times short.

(2) Squeeze cementing when water cones suddenly through fractures. This is probably the first thing that comes to the geologist or engineer's mind. And in some instances this might be a good solution (although usually short-lived). Other possibilities discussed at the meeting included producing less gas, shutin some wells in, and praying.

A solution that worked out very well in a South American gas reservoir was to produce more water via gas lift through some key wells to slow down the advance of water toward the best production wells. A bonus was that the water production wells started little by little to contribute increasing gas rates.

(3) Poor completions. Many times they are the result of not drilling the wells thinking in terms of fractures. Improvements can be achieved in many instances by drilling underbalance. In some instances oil-base muds might help to alleviate damage. Cementing can be a significant problem. Cement can travel very long distances through fractures and can induce deep seated damage. There are instances where infill wells have found cement used in surrounding wells.

To avoid this problem, it is important to classify the fractured reservoir in terms of storage (see ref. 1, page 11). In a reservoir of Type A there is high storage capacity in the matrix and low storage in the fractures. In a reservoir of Type B there is about equal storage capacity in matrix and fractures. In a reservoir of Type C all storage capacity is in fractures.

I have noticed that the amount of damage by cement increases as we move from reservoirs of Type A toward reservoirs of Type C. As a result, in general, I recommend running open-hole completions in reservoirs of Type C and perforated completions in reservoirs of Type A.

References

1. Aguilera, Roberto: Naturally Fractured Reservoirs, 2nd Edition, Pennwell Books, Tulsa, Oklahoma ( 1995), 520 p.

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Technical Note # 6. March 16, 1998

Oil Production from Volcanic Rocks

By Dr. Roberto Aguilera

This note summarizes some reservoirs where oil production has been obtained from volcanic rocks. One example of a volcanic reservoir is provided by the Yacimiento 25 de Mayo, Medanito S.E., Neuquen, Argentina. Oil production is obtained from the Permian-Triassic Choyoi Group which by 1980 was producing more than 11,000 BOPD from volcanic rocks. This represented 25% of the production from the whole field which produced from 3 reservoirs (Choyoi Group, Petrolifera formation, and Quintuco formation).  Naturally fractured rhyolites, tuffites and tuffaceous sandstones were responsible for hydrocarbon production from the volcanic rocks.

Conventional and elaborated well log interpretation techniques indicated consistently a water saturation of 100 percent, in spite that some wells were producing clean oil with zero water cut (see ref. 1). Eventually the P1/2 statistical technique for naturally fractured reservoirs (see ref. 2, p. 259-264) was used in 30 cases, pointing correctly to water and hydrocarbon intervals in 26 cases, a success rate of 87 percent (ref. 1). In this case a totally unconventional rock was evaluated successfully with conventional well logs.

The P1/2 statistical parameter is a function of resistivity, porosity tool responses, and Archie's porosity (cementation) exponent, m. P1/2 has a normal distribution for intervals that are 100% saturated with water. Hydrocarbon-bearing intervals deviate from the normal distribution. The porosity (cementation) exponent, m, of naturally fractured reservoirs is smaller than m in conventional unfractured reservoirs. The larger the degree of fracturing the smaller the value of m. The limiting value of m is 1.0 for the case of an open uncemented fracture without solid to solid contact.

Oil production has been obtained from other volcanic naturally fractured reservoirs around the world. Examples are provided by Jatibarang field in Indonesia where production has been obtained from Eocene and Oligocene lavas (ref. 3), Jatibonico pool in Cuba where more than 1,200 wells were drilled in fractured serpentines (ref. 4), Pina reservoir in Cuba where production has been obtained from Upper and Lower Cretaceous tuffites (ref. 5), Hilbig pool in Texas which produced from Cretaceous palagonites (ref. 6), McArthur River field, Cook Inlet in Alaska which produced oil from Jurassic tuffites and volcanic sands (ref. 7), and the Kora oil field in New Zealand which found producible oil in an Upper Miocene volcanic zone (ref. 8).

References

1. Daniel, G.A, and Hvala, O.:" Analisis de Rocas Tobaceas y Volcanicas a Partir de Los Perfiles Sonico y de Resistividad (Grupo Choyoi - Yac. 25 de Mayo - Medanito S.E.)," Primer Congreso Nacional de Hidrocarburos, Buenos Aires, Argentina Nov. 29-Dec 3, 1982), p. 99-126.

2. Aguilera, Roberto: Naturally Fractured Reservoirs, Second Edition, PennWell, Tulsa, Oklahoma (1995), 521 p.

3. Kalan, T., Sitorus, H.P., and Eman, M.:" Jatibarang Field, Geologic Study of Volcanic Reservoir for Horizontal Well Proposal," Proceedings Indonesian Petroleum Association, Twenty third Annual Convention (October 1994).

4. Oil and Gas Journal, Vol. 44 (June 9, 1945), p. 76, (July 14, 1945), p. 92.

5. Rodriguez de Villavicencio, M., Segura, R. and Villavicencio B.: "Evaluacion de Rocas Vulcanogeno-Sedimentarias en la Republica de Cuba (Circa 1994).

6. Smiser, J. S. and Wintermann, D.: Character and Possible Origin of Producing Rocks in Hilbig Oil Field, Bastrop County, Texas", Bull. AAPG (1935) vol. 19, p.206-220.

7. Bailey, Lee (Unocal Alaska): Personal communication with Roberto Aguilera (March 16, 1998).

8. Bergman, S., Talbot, J. P., and Thompson, P.R.: "The Kora Miocene Submarine Andesite Stratovolcano Hydrocarbon Reservoir, Northern Taranaki Basin, New Zealand, "New Zealand Oil Exploration Proceedings (1992) 178-206.

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Technical Note # 5. January 2, 1997

The Power of Natural Fractures

By Dr. Roberto Aguilera

This short technical note is presented as a response to requests from some of our readers who wanted some dramatic examples regarding the power of natural fractures to transmit fluids in the subsurface. Rather than presenting examples from oil or gas reservoirs, I have selected a couple of cases associated with areas that can be visited where the power of natural fractures is constantly at work. One example is provided by Giant Springs near Great Falls, Montana. The other example is Medicine Lake in the Jasper National Park, Alberta. The information that I present in this note is quoted directly from text available at these two sites.

Giant Springs, Montana

The naturally fractured Madison limestone lies under most of Eastern Montana, and is about 250 million years old. Rainfall and melted snow soaks into the limestone where it is exposed on the slopes of the Little Belt Mountains. The water drains downward and then flows through openings in the limestone to the Great Falls area where it flows upward about 700 ft through natural fractures. It is then forced out at Giant Springs by a force of about 300 pounds per square inch.

Giant Springs discharges about 134 thousand gallons per minute. It contains calcium, magnesium, bicarbonate, and sulfate. It is excellent for growing trout. The entire trip of 38 miles from the Little Belt Mountains to Giant Springs takes many hundreds of years.

Medicine Lake, Alberta

There is a "mystery" at Medicine Lake in the Maligne Valley. In summer, Medicine Lake looks like any other lake in Jasper National Park. But by October, the lake vanishes, replaced until spring by a shallow stream winding sluggishly across mudflats to a few small pools. The water depth varies as much as 20 meters through the year.  Much of the time the lake has no visible outlet.

Indians believed the disappearance of the lake was by "big medicine" or magic, and they feared it. The "mystery", however, was solved by a geologic study. The bedrock in this part of the Maligne Valley fractured severely during uplift. Rainwater and snowmelt entered cracks and slowly dissolved a network of underground passages.

The upper Maligne River sinks into these passages through many openings in the valley floor. In summer, melt water from snow and glaciers swells the river, exceeding what the underground system can carry. The surplus water, dammed by a massive rock slide to the north, floods the basin and forms Medicine Lake.

At the onset of cooler weather in late August, the inflow is less than the drainage into the caves. The lake level drops, exposing the lake bottom until the cycle begins again the following summer. In the 1950s, fluctuating water levels hampered ferry service on the lake. A dam was proposed but never built, and an unsuccessful attempt was made to block the sink points using sandbags, mattresses and bundles of magazines.

Recently, the outflow of the underground system has been traced to a large group of springs in the Athabasca Valley, 17 km down valley from the lake. Although this may not be the world's largest underground stream, the entrances are small and debris-choked, and the passages remain frustratingly inaccessible.

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Technical Note # 4.  October 15, 1996

Oil and Gas Reserves in Naturally Fractured Reservoirs

By Dr. Roberto Aguilera

The estimation of reserves of oil, gas, and related substances has been a hot topic since the very beginning of the oil industry. Over the ensuing years, the concept of reserves has meant different things to different people within this industry, with each evaluator, oil and gas company, financial agency, securities commission, and government department using its own version of the definitions. The problem is even more complex in the case of naturally fractured reservoirs.

This technical note highlights some of Servipetrol's experiences when attempting to classify hydrocarbons reserves as proven, probable and/or possible. The definitions we tend to use in most instances were published in the Petroleum Society of CIM Monograph No. 1 Determination of Oil and Gas Reserves published in Calgary, Canada (1994). The following is a summary of the definitions presented in that document:

Remaining Proved Reserves are those remaining reserves that can be estimated with a high degree of certainty, which for purposes of reserves classification means that there is generally an 80 percent or greater probability that at least the estimated quantity will be recovered. These reserves may be divided into proved developed and proved undeveloped to identify the status of development. The proved developed may be further divided into producing and nonproducing categories.

Probable Reserves are those remaining reserves that are less certain to be recovered than proved reserves, which for purposes of reserves classification means that generally there is a 40 to 80 percent probability that the estimated quantity will be recovered. Both the estimated quantity and the risk-weighted portion reflecting the respective probability should be reported. These reserves can be divided into probable developed and probable undeveloped to identify the status of development.

Possible Reserves are those remaining reserves that are less certain to be recovered than probable reserves, which for purposes of reserves classification means that generally there is a 10 to 40 percent probability that the estimated quantity will be recovered. Both the estimated quantity and the risk-weighted portion reflecting the probability should be reported. These reserves can be divided into possible developed and possible undeveloped to identify the status of development.

In addition, many other organizations have published reserves definitions including the U.S. Department of Energy, the Securities & Exchange Commission and Financial Accounting Standards Board, The Canadian Institute of Chartered Accountants, the Society of Petroleum Evaluation Engineers, the Society of Petroleum Engineers, the American Gas Association, and the World Petroleum Congress.

Based on Servipetrol's experience the following guidelines have been adopted within our organization for estimating oil and gas reserves in Naturally Fractured Reservoirs:

Volumetric Estimates.- Most naturally fractured reservoirs we are familiar with are characterized by low matrix porosities (much lower than 10%) and low matrix permeabilities (much lower than 1 md). For these reservoir characteristics it is difficult to place a reasonable certainty on volumetric estimates of original hydrocarbons-in-place, recoveries and hence reserves. As a consequence, as a general rule, we recommend placing reserves from volumetric calculations in the possible category.

Material Balance Estimates.- These techniques are very useful in conventional unfractured reservoirs but can easily lead to gross errors in naturally fractured reservoirs. A tank material balance cannot properly handle permeability anisotropy, permeability contrast between matrix and fractures, matrix and fracture porosities, skin, net pay, structural position of each well, gas or water influx via natural fractures, etc... As a consequence, as a general rule, we recommend placing reserves from material balance calculations in the probable category. We upgrade material balance estimates to the proved category when the production history is long, and the quality of the pressure data and the oil, gas, and water production data is good. Beware of possible changes in fracture communication and possible fracture closing as the reservoir is being depleted.

Production Decline Estimates.-  For short production histories, reserves estimates from production decline curves should be placed in an unproved category. Long production histories should lead to reasonable estimates of proved oil reserves. In general, we do not recommend decline curves for estimating reserves of gas reservoirs unless the wells are at a late stage of production where a constant surface compression pressure is being utilized.

Reservoir Simulation Estimates.- Although imperfect, this is the tool that in our opinion provides the most reliable source of information for estimating recoveries and proved reserves. A significant amount of high quality data is required. The longer the production history, the more reliable are the forecasted results. We must emphasize that although reservoir simulators are good tools in general, the quality of the results will be only as good as the quality of the input data. Beware of the indiscriminate use of corner point geometry. A grid that reproduces perfectly the structural configuration of the reservoir provides a nice cosmetic effect but might lead to very erroneous results. Try to keep your simulation grid as orthogonal as possible.

References

Aguilera, R.: Naturally Fractured Reservoirs,  Chapter 6, Economic Evaluation and Reserves, PennWell Books, Tulsa, Oklahoma (1195).

Determination of Oil and Gas Reserves, Petroleum Society of CIM Monograph No. 1, Calgary, Canada (1994)

© 1996 Copyright by Servipetrol Ltd. All rights reserved.

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Technical Note # 3. August 9, 1996

Undiscovered Naturally Fractured Reservoirs

By Dr. Roberto Aguilera

I am firmly convinced that there are significant volumes of hydrocarbons around the world that have been left behind pipe as undiscovered, or behind plugged and abandoned wells because of  (1) incorrect pressure extrapolations, (2) poor completions, and (3) failure to intersect the natural fractures.

1) Incorrect Pressure Extrapolations.-  These might occur when the infinite-acting radial flow period is not reached during the test. The typical drawdown and buildup behavior of a well in a naturally fractured reservoir is characterized by an "S" shape (theoretically two parallel straight lines with a transition period in between.  Many times the first straight line is masked by wellbore storage effects).If the buildup is short and the test reaches only the transition period, an extrapolation on a Horner plot could be made accidentally through this transition period leading to a small extrapolated  pressure and the conclusion that there is quick reservoir depletion. Under these circumstances the well may be abandoned. In most instances the pressure derivative is not going to help in reaching a different conclusion. If the buildup had been longer the last straight line corresponding to the infinite-acting radial flow period would have been reached and the extrapolation would have been more realistic - perhaps indicating that the reservoir was not under strong depletion.

2) Poor Completions.- The conventional wisdom is that a good well completion should be carried out in intervals that meet certain porosity, permeability, and water saturation cutoff criteria.

The porosity cutoff assumption has to be treated very carefully in naturally fractured reservoirs. It has been found through laboratory work, examination of outcrops, cores, and production logs that, other things being equal and for the same physical environment, the degree of natural fracturing is more intense in those intervals with the lower porosities. As a consequence, if we ignore the intervals with the lowest porosities during testing and completion, we might be bypassing  the intervals with the best fracture development, i.e., the intervals that will provide the necessary rates to establish commercial production. The idea that I am trying to sell is not that we should not test the intervals with the highest porosities. Rather that we should not overlook the intervals with the lowest porosities.

The use of a permeability cutoff is a well established means of determining net pay in conventional non-fractured reservoirs. In my opinion, however, this is a poor practice in naturally fractured reservoirs. A matrix permeability of 0.01 md is not capable, in general, of contributing commercial production into a wellbore because of the small surface area of the matrix exposed to the wellbore. However, the same 0.01 md matrix permeability can allow very efficient flow of hydrocarbons from the matrix into a well developed system of natural fractures. This occurs because in this instance there is a large surface area exposed to the matrix via natural fractures. Flow of hydrocarbons from a tight matrix into natural fractures has been demonstrated through micro-simulation of naturally fractured cores, well testing and numerical simulation.

The use of water saturation as cutoff criteria in naturally fractured reservoirs must be handled carefully. There are instances in which the water saturation of the tight matrix might approach 100 percent and the hydrocarbon saturation of the natural fractures might approach 100 percent. Because the pore volume of the matrix is in many cases larger than the pore volume of the fractures, a conventional well log interpretation might lead to a very large value of water saturation. Under these circumstances the decision might made to abandon the well. Be careful with your log interpretation. As a general rule, the petrophysical exponents m and  n should be smaller in naturally fractured reservoirs than in conventional unfractured reservoirs. The larger the degree of communicating natural fracturing the smaller the values of  m and n.

Sometimes a thin bed might not be considered important from an economic point of view, especially in an exploration well. It must be kept in mind, however, that other things being equal and for the same physical environment, the larger degree of natural fracturing occurs in the thinner beds.  Thin high permeability beds might not be important from a hydrocarbon-storage point of view  but they might communicate with other parts of the reservoir where substantial amounts of hydrocarbons might be located. As an example, there is an oil well in Alberta producing from a thin fractured interval which has accumulated large amounts of oil.  This well is surrounded by at least six dry holes. The dry holes are within the drainage area of the production well.

DSTs and RFTs are powerful tools, but care must be exercized in their interpretation because they are not fully diagnostic in naturally fractured reservoirs. For example,  if only the matrix is tested, these tools will indicate correctly very low permeabilities and no flow capabilities. Even if the fracture is covered by the test, the recovery might be only mud that has been lost via the natural fractures during drilling operations.

3) Failure to Intersect Natural Fractures.- Most natural fractures of commercial importance are vertical or sub-vertical. Under these circumstances vertical wells do not stand the same probability of success as directional or horizontal wells in naturally fractured reservoirs. These  types of failures with vertical wells have been of common occurrence. An example is provided by well PV6 in the Palm Valley gas field of Australia. The well was air-drilled vertically but it did not intersect any significant fractures in the formation of interest (Pacoota P1 formation, Ordovician Age) and the production was essentially zero. When the same borehole was deviated, it intersected a high inclination fracture(s), and the Pacoota P1 yielded 137 MMscfd.

CONCLUSION-. Based on my experience to date I am convinced that many naturally fractured hydrocarbon reservoirs around the world have not become profitable discoveries and have been abandoned because of  (1) incorrect pressure extrapolations, (2) poor completions, and/or (3) failure to intersect the natural fractures. Proper geological and engineering techniques developed specifically for evaluating and exploiting naturally fractured reservoirs should help to avoid these potential problems.

References

1. Aguilera, R.: Naturally Fractured Reservoirs, 2nd Edition, PennWell Books, Tulsa, Oklahoma (1995), p. 77.

2. Aguilera, R., et al.: Horizontal Wells, Formation Evaluation, Drilling and Production, Including Heavy Oil Recovery, 1st Edition, Gulf Publishing Co., Houston, Texas (1991), 401 pp.

© 1996 Copyright by Servipetrol Ltd. All rights reserved.

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Technical Note # 2. April 18, 1996

Hydrocarbon Production from Naturally Fractured Granite

By: Dr. Roberto Aguilera

   Oil production from granite rock is not common but it does exist in various countries as shown below. Any time I have studied commercial hydrocarbon production from granite rock, in particular, or basement reservoirs, in general, two important requirements have been met: (1) the granite is contiguous to a source rock, or oil/gas reservoirs, and (2) the basement is naturally fractured.

     In my opinion the origin of oil is organic. Oil production from fractured granite does not mean that the origin of oil is igneous. It simply means that hydrocarbons migrated into the fractured granite from a source rock or an oil/gas reservoir contiguous to the granite. A possible explanation of how hydrocarbons migrate into naturally fractured granite is provided by the theory of dilatancy as explained by Mead (1925)and McNaughton (1953) and presented by Aguilera (1995). Based on this theory when the rock fractures, a dilatancy zone and a vacuum are created. As a result, hydrocarbons (and in some cases water) start moving into the dilatant zone, due to the vacuum produced by the fractures. Capping of the basement rock following migration might be provided for example by deposition of calcite in some of the fractures.

   I find it interesting that many oil companies stop drilling operations the minute basement is found. It is my strong recommendation that, on the contrary, drilling should be continued into basement for at least 300 meters, preferentially with a slanted hole, especially if a source rock rests on top of the basement. I anticipate significant discoveries in basement rock if this procedure is followed.

   The following is a partial list of granite-associated reservoirs:

·        Hall Gurney fld., Kansas, USA ,  Precambrian fresh pink biotite, granite  430 BOPD  **

·        Gorham fld. Kansas, USA,  Pre-Cambrian fresh pink biotite, granite 300 BOPD  **              

·        Ames Crater. Oklahoma, USA ,  Cambro-Ordovician  Arbuckle dolomites and Pre-Cambrian granites,  Resources:  50 MMSTBO and 20 BSCF  **

·        Beruk Northeast fld, Central Sumatra, Indonesia ,  Weathered granite, 200 BOPD  and 25 BWPD  **   

·        La Paz/Mara flds, Venezuela ,  Igneous, metamorphic granite, >1000 BOPD  **  

·        Amal fld., Libya,   Pre-Cambrian weathered granite and rhyolite, 1500 to 7500 BOPD  **  

·        Xinglontai, Liaoning, China,  Archean granite, Mesozoic volcanic, 210 to 750 BOPD   **

·        Gulf of Suez, Egypt ,  Granite, > 1000 BOPD  **                                                                 

·        Yemen ,  Granite,  9000 BOPD  **  

·        Some Russian flds, granite, >1000 BOPD  **                                                                                   

References:

Aguilera, Roberto: Naturally Fractured Reservoirs, 2nd Edition, PennWell Books, Tulsa, Oklahoma (1995).

Mead, W. J. "The Geologic Role of Dilatancy," Journal of Geology, (1925), 686-698.

McNaughton, D. A. "Dilatancy in Migration and Accumulation of Oil in Metamorphic Rocks," Bulletin AAPG, No.2, (February 1953) 217-231.

© 1996 Copyright by Servipetrol Ltd. All rights reserved.

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Technical Note # 1.  December 29, 1995

How big is Fracture Porosity?

By: Dr. Roberto Aguilera

   This is probably the most common question I have been asked during the last 20 years by clients as well as participants in my short course on "Naturally Fractured Reservoirs". The answer is that it can be as large as 100%. Why?  well - because fracture porosity, as opposed to matrix porosity,  is strongly scale-dependent.  For example, if we are drilling a well and we have a 1-foot drilling break, the value of fracture porosity at that particular location within that single foot is 100% (Other types of secondary porosity might also be present).   However, at the scale of the whole reservoir, the average value of fracture porosity is in many cases less than 1%. The following are some values of fractured porosity published in the literature and compiled in ref. 1:

 Austin Chalk, Texas: 0.2% -  Monterey formation, California: 0.01 to 1.1% - South African karst zone: 1 to 2% - CT scan samples: 1.53 to 2.57% - Epoxy injection examples: 1.81 to 9.64% - Amal field, Libya: 1.7%, Beaver River gas field, British Columbia: 0.05 to 5% - Ellenburger, Texas: 0.23 to 1.04% - Mississippian lime, Oklahoma: 0.5% - Lacq Superieur, France:  0.5%.

   Reservoirs producing hydrocarbons from only fracture porosity are in many instances characterized by high production rates that decline to uneconomic limits in a short period of time. However, there are exceptions. For example, the Edison and Mountain View fields in the San Joaquin Valley of California and the El Segundo, Wilmington, and Playa del Rey Fields in the Los Angeles Basin produced above 15,000 BOPD from fractured pre-Cretaceous basement schist. The storage in the basement rock of the La Paz-Mara oil fields in  Western Venezuela is in the Fracture system. The Amal field in Libya  produces from a Cambrian fracture quartzite. The reservoir area is approximately 100,000 acres, and reserves are in the order of 1,700 MMSTB. And there are many other cases.

  Thus, also fractured porosity is in general very small, there is probably enough evidence to banish the generalized assumption that storage of hydrocarbons in fractured systems is always negligible. This leads me to a strong recommendation: If you drill a well and reach basement, do not stop at that point (unfortunately, this is what is done in most cases). On the contrary,  keep on drilling at least a couple of hundred meters (preferentially with some deviation). You might be happily surprised especially if  the basement is overlain by a source rock. 

Reference:

Aguilera, Roberto: Naturally Fractured Reservoirs, PennWell Books, Tulsa, Oklahoma (1995), p. 7

© 1995 Copyright by Servipetrol Ltd. All rights reserved.


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