SEALS—A CRITICAL ELEMENT TO SUCCESSFUL EXPLORATION AND PRODUCTION

Based on a workshop sponsored by PTTC's Eastern Gulf Region on March 29, 2000 in Jackson, Mississippi.

BOTTOM LINE

Seals are commonly an overlooked component in the evaluation of a potential hydrocarbon accumulation. Seals can be detected by a variety of tools such as pressure tests, seismic amplitude analysis, and high pressure capillary curves. Capillary pressure tests are a very useful method to evaluate seals.

PROBLEM ADDRESSED

In order for a hydrocarbon accumulation to exist there must be reservoir rocks, seals, a trap, and hydrocarbon charge. Because seal capacity is the maximum hydrocarbon column height that a seal can trap, seals can be defined by high pressure mercury-air capillary curves. Capillary pressure in rocks is controlled by interfacial tension, wettability, and the pore throat size distribution. Capillary pressure tests are extremely useful in determining the accumulation process and the initial distribution of reservoir fluids. They are also very useful for consideration of waterflood and water drive behavior.

KEY WORDS:

Compartmentalized Gas Accumulations, Flow Barrier Evaluation, Pressure Seals, Procedures and Pitfalls

SPEAKERS

Seals and Flow Barrier Evaluation
Robert Sneider, Robert M. Sneider Exploration

Pressure Seals and Compartmentalized Gas Accumulations
Ronald Surdam, Institute for Energy Research, University of Wyoming

Evaluating Hydrocarbon Seal Potential: Procedures and Pitfalls
Charles Vavra, Arco E&P

TECHNOLOGY OVERVIEW

Seals can be detected at micro-scale (core scale) and at mega-scale (prospect scale) using the following tools and techniques: seismic amplitude analysis and offsets; well logs calibrated with rock (e.g. Resistivity, SP-GR, Neutron, Density and Acoustic logs); core and cuttings through high pressure capillary curves and microscopic measurements; hydrocarbon shows; fault displacement vs. lithologies; and pressure tests (DST's and Pulse tests).

Fundamental Concepts of Seals and Flow Barriers

In order to be effective, hydrocarbon seals must be laterally continuous. Sneider defines relevant terms:

• A seal is a sediment, rock or immobile fluid with a high to very high capillary entry pressure which will dam or trap hydrocarbons. A barrier is a type of seal lithology within a reservoir that prevents fluid flow during production. A baffle impedes flow.
• Capillary entry pressure is the capillary pressure at which the nonwetting phase first displaces the wetting phase. Hydrocarbon column height is the column of oil and/or gas that a seal can hold before hydrocarbons leak out. The column height is a function of seal entry pressure and the density difference between water and hydrocarbons.
• Seal capacity is the capillary pressure at which hydrocarbons will leak into a seal. Breakthrough pressure is the capillary pressure at which the nonwetting phase forms a continuous network within the seal. At this pressure, the nonwetting phase will leak or flow through the seal.
• Typical seal lithologies, from most ductile to most brittle, include, salt, anhydrite, kerogen-rich shales, clay mineral-rich shales, dense carbonate mudstones, silty shales, dense mudstones, tightly cemented sandstones, sandy shales, anhydrite-filled dolomite, carbonate-/silica cemented sandstones, and cherts.
• Any lithology can be a seal. All that is required is that the minimum displacement pressure of the seal rock be greater than the buoyancy pressure of the hydrocarbons in the accumulation. Thus the size of the continuous pore throats and the density of the hydrocarbons and water are of great significance.

Fault Seals

The sealing capacity along a fault is not constant. In general, it depends on the amount of fault displacement, feet of "shale" smeared along the fault, the percent of clay minerals in the "shales", and the number of faults within the fault plane. In addition, some sealing faults may "break down" during production and allow fluid movement. Fault seals are a combination of geometrical juxtaposition of sealing lithologies and physical/chemical alteration of the fault rocks (clay smearing, grain crushing, and diagenetic alteration). Processes that reduce petrophysical properties, thereby increasing the sealing capacity of a fault, include:

• Cataclasis–occurs at intermediate to deep burial depths. Cataclasis primarily reduces grain size by breakage, thereby packing grains more efficiently.
• Clay smearing–includes injection of clay into a fault, deformation of shale along the fault past the reservoir lithology and deformation of shale-rich sandstones.
• Deformation creating porosity collapse mixes fines with the framework grains.
• Cementation–Dilation along faults increases permeability and therefore increases the volume of fluids flowing along the fault. Increased precipitation within the fault zone often results.
• Pressure Solution–Post-deformation pressure solution requires sufficient temperature and clay at contact and nucleation sites. The presence of phyllosilicates at grain-to-grain contacts increases dissolution. Dissolved grain material is often reprecipitated on adjacent grain surfaces, thereby reducing porosity.

Petrophysical Properties of Seals

Porosity is not a criterion with which to identify a seal. Vertical permeability, however, determined under simulated in situ stress, and capillary pressure curves are very useful to evaluate and quantify rocks as seals. Many good seals have entry pressures of more than 1000 psi; excellent seals have air-mercury entry pressures in excess of 3000 psi.

Seal capacity is the maximum hydrocarbon column height that a seal can trap and can be quantified as the displacement pressure at 5-10% nonwetting phase saturation. The height of the hydrocarbon column trapped (in over 300 case studies) is equivalent to the sealing capacity of the weakest seal. Key parameters controlling seal capacity can be divided into rock and fluid types. Rock parameters include ductility, continuity, and the size distribution of the continuous pore throats that determine capillary entry pressure. Fluid parameters include density of the pore water and hydrocarbons and the interfacial tension of the fluids. Thickness, porosity and permeability are not key parameters.

Thus, seals can be defined by high pressure mercury-air capillary curves. Seals are classified by lithology and hydrocarbon column height. Samples from known seal types, SEM images, and capillary pressure curves can be used to estimate seal type under a binocular microscope at 50X magnification.

Capillary Pressure and Hydrocarbon Entrapment

Capillary pressure is a major factor in controlling the initial distribution of hydrocarbons. When hydrocarbons enter a reservoir and displace the interstitial (connate) water, capillary forces together with reservoir and seal pore and fluid properties influence the amount and distribution of hydrocarbons. The amount and distribution of initial hydrocarbon in a reservoir depends on the density of the water and hydrocarbons, rock properties (especially pore-size distribution), and the depth within the reservoir (i.e., the height above the free water level).

Three factors control capillary pressure in rocks: interfacial tension between hydrocarbons and water, wettability of the rock surfaces, and the size distribution of the pores, especially the interconnection of the pore throats. Capillary pressure in a pore exists across the fluid interface between oil and water. The property of the interface is called interfacial tension when two liquids are involved and surface tension when a liquid and gas are involved. Absorption of a rock surface for a specific fluid is called wettability. If water is absorbed on the grain surface more strongly than oil or gas (water adhesive forces > cohesive forces), the grain surface is said to be water wet. The grain surface is oil wet if oil is absorbed more strongly than water (water adhesive forces < cohesive forces). In a simple capillary tube, the capillary pressure between a nonwetting phase (oil) and a wetting phase (water) can be defined in terms of the radius of curvature of the interface between the fluids, the radius of the capillary tube, the interfacial tension of the fluids and the wetting or contact angle.

Capillary pressure tests are run to compute the effect of capillary pressure on fluid distribution and likely production. When the test is run with a nonwetting fluid (e.g., oil) displacing a wetting fluid (e.g., water), the test is called drainage capillary pressure. The drainage test is most commonly used in determining the accumulation process and the initial distribution of reservoir fluids. When the test is run with a wetting fluid displacing a nonwetting fluid, the test is called imbibition capillary pressure. Imbibition tests are started at irreducible water saturation and are useful in considering waterflood and water drive behavior.

Rocky Mountain Laramide Basins

Significant portions of the Cretaceous shales below about 8,000-9,000 ft in the Rocky Mountain Laramide Basins (RMLB) are overpressured on a basinwide scale. Change from normally pressured to overpressured regimes coincides with marked changes in geochemical and geophysical properties (sonic transit time) of the Cretaceous rock/fluid system. Sandstone bodies within the overpressured shale section are subdivided stratigraphically and diagenetically into relatively small, isolated, gas-saturated, anomalously pressured compartments.

The driving mechanism of the pressure compartmentalization is the generation and storage of liquid hydrocarbons that subsequently react to gas, converting the fluid-flow system into a multiphase regime in which capillarity controls permeability. As additional hydrocarbons are generated and the oil-to-gas reaction proceeds, the system becomes saturated with hydrocarbons. This results in the expulsion of free water and greatly increases displacement pressures, which cause the low-permeability elements acting as fluid-flow barriers to form capillary seals. Overpressure persists down to the lowermost organic-rich Cretaceous shale. Typically the rocks below these shales in the Powder River and Wind River basins are normally pressured.

Two elements crucial to the development of prospects in the deep, gas-saturated portions of the RMLB are the determination and three-dimensional evaluation of the pressure boundary between normal and anomalous pressure regimes and the detection and delineation of porosity/permeability "sweet spots" (areas of enhanced storage capacity and deliverability). Eighty percent of the gas production from Cretaceous rocks in the RMLB is from an interval extending from the pressure boundary down to 2,000 ft below this boundary.

CONNECTIONS:

Robert Sneider
Robert M. Sneider Exploration
11767 Kathy Freeway, Suite 300
Houston, TX 77079-1716
Phone: 281-531-9944, Fax: 281-531-6352
E-mail: irtrms@neosoft.com

Ronald Surdam
Institute for Energy Research, University of Wyoming
P.O. Box 4068
Laramie, WY 82071-4068
Phone: 307-766-4200, Fax: 307-766-2737
E-mail: rcsurdam@uwyo.edu

Charles Vavra
Arco E&P Technology
2300 W. Plano Parkway
Plano, TX 75075-8427
Phone: 972-509-6420, Fax: 972-509-3017
E-mail: vavra@arco.com

For information on PTTC’s Eastern Gulf Region and its activities contact:
Ernest Mancini, Professor of Geology, University of Alabama
100 E. Boyd St., Room N131, Norman, OK 73019-0628
ph 205-348-4319, fax 205-348-0818, e-mail emancini@wgs.geo.ua.edu

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