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Contents:

Acknowledgements
Abstract
Introduction
Description & Cause
Pore Systems & Relative Permeability
Critical Water Saturation Versus Irreducible Water Saturation
Testing & Production Problems
Effects of Wettability
Conclusions
References Cited
Figure captions

   
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EXPLORING FOR UNDERSATURATED RESERVOIRS

Monty E. Hoffman
Safford Exploration, Inc.
6565 West Hoover Place
Littleton, Co 80123
Contact Monty for more information: msaffordexp@aol.com

ACKNOWLEDGEMENTS

This paper has required integrating concepts from many different fields. It would not have been possible without the help of people too numerous to mention. To all of those people I would like to give special thanks and to acknowledge that I couldn’t have written it without your help.

Abstract
Recent work has documented the existence of reservoirs that are undersaturated in water and are in capillary pressure non-equilibrium. These reservoirs will spontaneously imbibe water if they are drilled or completed with water based fluids. This imbibition causes the reservoir to water block and is very difficult to remove because it requires returning the reservoir to a non-equilibrium state. Once the reservoir is water blocked, it may produce nothing at all, or it may produce water greatly in excess of any water that was lost to the reservoir, even if it would have produced all hydrocarbons if properly drilled.

Undersaturated reservoirs form by post hydrocarbon migration uplift and erosion. This removal of overburden causes the water to cool and shrink and the pores to dilate. This increases the pore volume and decreases the water volume and the reservoir is in capillary pressure non-equilibrium.

Wettability changes in a reservoir can control what parts of an undersaturated reservoir can be water blocked, since water can only be imbibed if it is the wetting phase. Production changes caused by wettability changes can mimic the distribution of production that would be expected from water, transition, and hydrocarbon zones in a reservoir, but the geophysical logs will not show the expected fluid changes.

Any undersaturated reservoir that has been drilled and completed with a water based fluid has not been properly evaluated. Lack of hydrocarbon recovery or recovery of large volumes of water does not preclude commercial production of hydrocarbons if the reservoir is properly drilled.

Introduction
Reservoirs that are in non-equilibrium with respect to capillary pressure in the subsurface and that can produce water more readily than oil or gas when exposed to water based drilling and completion fluids have been identified (Bennion, et al, 2000). These reservoirs are undersaturated with water for their present capillary pressure. This has significant implications in terms of drilling methods and drilling fluids. Improperly drilled wells in these types of reservoirs will produce no fluids or are capable of producing entirely different fluids than the reservoir would produce if properly drilled. Stated simply, an oil or gas reservoir can be made to produce predominately water and produce an amount of water that is much greater than any water lost during the drilling process.

Recent drilling in undersaturated reservoirs has resulted in the discovery of an economically viable reservoir with greater than 5 TCF in place by Encana in British Columbia (Encana Corp, 2002). This reservoir had many wells drilled through it before it was recognized as undersaturated and subsequently drilled properly. There are many similar type reservoirs that have been penetrated and gone unrecognized because they cannot be evaluated and produced by standard oil field practices.

Description and Cause
Figure 1 is from Bennion, et al’s, (2000) article and shows the capillary pressures for undersaturated reservoirs. Initial water saturation (point “A”) is less than the capillary pressure equilibrium curve (point “B”). If any water is introduced into the borehole in an undersaturated reservoir, capillary forces spontaneously imbibe water into the reservoir, increasing the water saturation and relative permeability to water and simultaneously decreasing the relative permeability to hydrocarbons (Bennion, ET, al, 2000). The imbibed water is difficult to remove because capillary forces act to hold the water in place to maintain capillary equilibrium.

While Bennion, et al (2000) have recognized this class of reservoirs, their explanation of their development, moving large volumes of gas through them to dehydrate them, is difficult to fit to a geologic and hydrologic model. A better explanation can be derived from Ferran’s (1973) explanation of low pressured Morrow sands.

We recognized early on in our pursuit of these reservoirs that many, but not all, of the undersaturated reservoirs are also underpressured and that there may be a genetic link between the underpressured state and the undersaturation. Ferran proposes that the underpressuring occurs because uplift and erosion cause three changes that reduce the water volume in the reservoir. First is pore dilation in the reservoir as the overburden pressure is removed. Second is the shrinkage of the water as it cools (Barker, 1972; Kennedy and Holser, 1966). Third, is the resaturation of the surrounding shales as they expand when the overburden pressure is removed. Examination of a pressure profile in the Oklahoma panhandle (figure 2) shows that the gradient is not formation or lithology dependent, so having surrounding shales does not appear to be a critical requirement and its contribution is minimal. These processes all reduce water volume relative to volume of pore space and cause underpressuring and undersaturation, but cooling has by far the greatest influence.

Figure 3 illustrates the development of undersaturation. After hydrocarbon migration and emplacement, point 1 shows the initial capillary pressure and saturation condition at a point in the reservoir. After uplift and erosion, Sw has shifted to point 2 and the reservoir is out of capillary pressure equilibrium. If any water is made available to the reservoir, it will imbibe it in an attempt to return to point 3, the capillary pressure equilibrium point on the imbibition curve.

Post hydrocarbon migration uplift and erosional removal of overburden will result in a reservoir that has less water volume in the pore space than when it was charged with hydrocarbon and it will be in a non equilibrium situation. The volume that was occupied by water is taken up by gas expansion and gas that comes out of solution in the oil and expands. Almost all of the sixty undersaturated reservoirs that we have studied have low GORs and gas caps on low gravity oil reservoirs.
.

Pore Systems and Relative Permeability
Figures 4 through 6 are modified from Standing (1975) and show the progression of fluid distribution in pore sizes upward through a hydrocarbon accumulation. Starting at the free water surface, where capillary pressure is zero, all pores are filled with water (Figure 4).

Moving up into the transition zone, with increasing hydrocarbon column height and corresponding increase in capillary pressure due to buoyancy, the hydrocarbons displace the water from the pores, with the water being moved out of the largest pores first. This occurs because capillary forces are lowest in the larger pore systems and the water will move from these pores with a lower buoyancy force (figure 5). At high hydrocarbon column heights, the hydrocarbons have displaced all nearly of the water that can be moved and the reservoir is at irreducible water saturation (Figure 6).

Because the hydrocarbons are sorted into different pore systems by capillary entry pressures (Standing, 1975), the relative permeability to different fluids can be altered by blocking off different pore systems. If the hydrocarbon system is blocked off by water block, this will cut down the cross sectional area of the reservoir and increase the force on the water system that remains open. Darcy’s Law can be rewritten in the form:

Where q is the volume flux (volume per unit time) in centimeters per second for horizontal flow, K is the permeability constant in darcys, A is the cross sectional area in square centimeters, µ is the fluid viscosity in centipoises, and dp/dx is the hydraulic gradient (the difference in pressure, p, in the direction of flow, x) in atmospheres per centimeter.
As the cross sectional area (A) decreases, the force across the water pore system (dp/dx) increases. This increase in force is enough to overcome the capillary forces that had previously prevented the water from flowing in part of the water pore system. Water that was previously immobile is now mobile. By damaging the reservoir by water block, the critical water saturation of the reservoir has been reduced and a large amount of water that would not have moved can now be produced in the well bore. The relative permeability to hydrocarbons has been greatly decreased and the relative permeability to water has been increased in the reservoir. The reservoir will flow water in amounts that are greatly in excess of any water lost during drilling, even though the reservoir would have made no water if it had not been damaged.

Critical Water Saturation
versus Irreducible Water Saturation
Figure 7 (Arps, 1964) shows a generalized relationship between water saturation, relative permeability, and capillary pressure. The diagram shows the difference between critical water saturation (CWS), defined as the water saturation below which the formation will only flow oil or gas, and irreducible water saturation (IWS), defined as the water saturation below which little additional water can be displaced from the formation by a higher capillary injection pressure. It shows that the water saturation at which we start to produce water free oil is not determined by irreducible water saturation, but by the critical water saturation. When Krw is zero (CWS), only oil or gas will be produced regardless of how much mobile water is in the formation.

Figures 8 and 9 show calculated relative permeability and hydrocarbon column height curves for a 2.8 millidarcy core plug from the Mississippian Limestone in North Ness City Field, Ness County, Kansas. CWS is 47% water saturation and IWS is 5% water saturation or less. Figure 9 shows that CWS is reached at 75 feet above the free water surface but IWS still isn’t reached at 4000 feet above the free water surface. Undamaged, this reservoir will produce 100% oil 75 feet above the free water surface. Damaged it could produce significant water 4000 feet above the free water surface and produce water greatly in excess of any water lost during drilling.

Testing and Production Problems
Bennion, et al, (2000) recognized that in a reservoir that is at irreducible water saturation, the primary problem with introducing water into these reservoirs from drilling fluids is that it changes the relative permeability to oil or gas and severely limits hydrocarbon production.

For reservoirs that are below critical water saturation but not at irreducible water saturation, the problem is even more difficult. Water blocking the hydrocarbon porosity system causes the critical water saturation of the reservoir to be reduced by increasing the force on the water system and overcoming the capillary forces that have held the water immobile in part of the water pore system. Part of the water that was immobile before the reservoir damage is now mobile. When the reservoir is flow tested, it will produce little or no hydrocarbons and large amounts of formation water. In standard oil field practice, the zone will be considered wet and abandoned, even though the geophysical logs show hydrocarbon saturation.

Effects of Wettability
Wettability adds a further complication to the problem. Wettability of a reservoir is a variable that is affected by capillary pressure, oil and water chemistry, fluid-fluid interactions and rock-fluid interactions. Work on wettability over the last ten years has focused on wettability changes caused by reservoir condition variations. (Jerauld and Rathmell, 1997; Jain, et al, 2002) This work has resulted in a recognition that wettability can change in a reservoir with the height of the hydrocarbon column and the subsequent change in capillary pressure and initial water saturation. It can also change from reservoir to reservoir in an area because of oil or water chemistry changes.

Because a reservoir will only imbibe the wetting phase, the ability to damage a reservoir by water block changes as the wettability changes. A reservoir that is capable of producing only water low in the hydrocarbon column where it is still water wet will be capable of producing some hydrocarbon as the reservoir changes to mixed wet and will produce all hydrocarbons when it becomes mostly oil or gas wet.

This distribution of production mimics what would be expected from water, transition, and hydrocarbon zones in a reservoir. The difference is that the log character does not show the fluid changes that would be expected as the logs pass from zone to zone. Improper drilling and completion techniques can result in water tests in the hydrocarbon column. This can result in a large part of the hydrocarbon column being considered as being below the free water surface. Properly drilled, the hydrocarbon production can be extended down dip. (Figure 10).

Asphaltene compound deposition on grain surfaces also changes rocks from water wet to mixed wet. In an area where there are oils with different asphaltene contents, the oils with greater asphaltene content will become mixed wet and prevent water block. Oils that are high in paraffin content and low in asphaltene content tend to be water wet at lower water saturations.

Conclusions
1. Bennion, et al, (2000) have documented the existence of reservoirs that are undersaturated with regard to water in relation to capillary pressure equilibrium. Because of this, the reservoirs water block by spontaneous imbibition and are very difficult to return to a productive condition because it requires going from equilibrium to a non-equilibrium situation to remedy the damage.

2. Undersaturated reservoirs form when pore dilation and water cooling cause the volume of water relative to the pore space in the reservoir to shrink. This is caused by post hydrocarbon migration uplift and erosion.

3. Reservoir fluids are sorted into different pore systems by capillary entry pressures. The relative permeability to the different fluids can be changed by water blocking the hydrocarbon pore system.

4. If a reservoir is at irreducible water saturation, the water block will greatly reduce the relative permeability to hydrocarbons. If a reservoir is below critical water saturation but above irreducible water saturation it can produce all water even if it would produce all hydrocarbons if undamaged (Figure 11).

5. The amount of water produced can be greatly in excess of the amount of water lost to the reservoir during drilling and completion operations. This is caused by the water block lowering critical water saturation and causing previously immobile water to become mobile.

6. As reservoirs change from water wet to mixed wet to mostly oil or gas wet, the damage that can be done by water block changes. This mimics the distribution that would be expected going from the free water surface through a transition zone to irreducible water saturation. The geophysical logs can be used to tell whether the fluid recovery changes are due to fluid content changes or water blocking.

7. Any undersaturated reservoir that has been drilled and completed with water based fluids has not been properly evaluated. Lack of fluid recovery or recovery of large volumes of water does not preclude production of hydrocarbons if the reservoir is drilled properly.

REFERENCES CITED

  • Arps, J.J., 1964, Engineering Concepts Useful in Oil Finding: Am. Assoc. Petroleum Geologists Bull, Vol. 48, No. 2, pp. 157-165.
  • Barker, C., 1972, Aquathermal Pressuring-Role of Temperature in Development of Abnormal-Pressure Zones: Am. Assoc. Petroleum Geologists Bull, Vol. 56, pp.2068-2071.
  • Bennion, D.B., Thomas F.B., and Ma, T., 2000, Formation Damage Processes Reducing Productivity of Low Permeability Gas Reservoirs: Society of Petroleum Engineers Paper # 60325.
  • Encana Corp., 2002, News and Views, June 4, 2002 http://www.encana.com/news_and_views/4_0_20020604_1.shtml
  • Ferran, L.H., 1973, Evaluation of Abnormally High and Low Pressured Morrow Sands in Northwestern Oklahoma Using Well Logs and Water Sample Data: Univ. of Tulsa Master’s Thesis.
  • Jain, V. ,Chattopadhyay, S., and Sharma, M.M., 2002, Effect of Capillary Pressure, Salinity, and Aging on Wettability Alteration in Sandstones and Limestones: Society of Petroleum Engineers Paper #75189.
  • Jerauld, G.R. and Rathmell, J.J., 1997, Wettability and Relative Permeability of Prudhoe Bay: a Case Study in Mixed-Wet Reservoirs, SPE Reservoir Engineering, February 1997, pp. 58-65. (SPE Paper # 28576)
  • Kennedy, G.C., and Holser, W.T., 1966, Pressure-volume-temperature and phase relations of water and carbon dioxide, Sec. 16 in Handbook of physical constants (rev. ed.: Geol. Soc. America Mem. 97, pp.371-383.
  • Oklahoma State University School of Geology, 2002, Anadarko Basin Pressure Data http://www.okstate.edu/geology/gri/exa-pd.gif
  • Standing, M.B., 1975, Notes on Relative Permeability Relationships: Stanford University, CA.


FIGURE CAPTIONS

  • Figure 1 – Typical capillary pressure curves for undersaturated water wet porous media illustrating imbibition potential upon exposure to water based fluids. (Bennion, Thomas, and Ma, 2000)
  • Figure 2- Texas County, Oklahoma pressure-depth profile (Oklahoma State University School of Geology, 2002)
  • Figure 3- Development of undersaturated reservoirs by uplift and erosion
  • Figure 4- Pore size distribution of fluids below the free water surface (after Standing, 1975)
  • Figure 5- Pore size distribution of fluids in the transition zone (after Standing, 1975)
  • Figure 6- Pore size distribution of fluids at irreducible water saturation (after Standing, 1975)
  • Figure 7- Relationship of critical water saturation and irreducible water saturation to water saturation, relative permeability, and capillary pressure (Arps, 1964)
  • Figure 8-Calculated relative permeability, #2 Lyle Schaben well, sample #27, 4417.2 ft.
  • Figure 9- Capillary pressure curve, #2 Lyle Schaben well, sample #27, 4417.2 ft. Critical water saturation (CWS) shown
  • Figure 10-Additional available production in water blocked reservoirs
  • Figure 11- Results of water blocking at irreducible water saturation and below critical water saturation

 
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