Coring and Core Analysis (Borehole Environment)

Borehole Environment

Core Alteration During Recovery

There are a number of causes of core alteration during recovery, three of which are discussed below.

Filtrate Invasion

In most cases, filtrate from the coring fluid will invade the reservoir rock as the core is cut. This causes an increase in the filtrate saturation within the core and a change of in situ fluid saturations. The quantity of filtrate invading the core is dependent on both controllable and noncontrollable factors. The noncontrollable factors are related to reservoir rock and fluid properties. For example, a low pressure differential between the drilling fluid pressure and reservoir pressure at the sandface, increased coring speed, high reservoir fluid viscosity, and low rock permeability impede core flushing. Fluids that exhibit low filtrate loss during standard static-type filtrate tests can still cause extensive flushing under the dynamics of coring. Evaluation of fluid invasion can best be made by adding a suitable tracer, such as nitrate or tritiated water, to the coring fluid, and then checking its concentration in the fluids extracted from the recovered core.

Fluid Expansion and Expulsion

During most coring processes, the core and fluids contained therein are subjected to a continuous reduction in pressure and temperature as the core is retrieved to the surface. Minor changes occur in the physical dimensions of the core, but reservoir fluids undergo substantial changes in volume. Oil releases gas from solution and the oil shrinks. The gas expands and escapes from the core, dragging oil and water with it. This process can be seen in some cores at retrieval, when both gas bubbles and oil bleeding can be observed on the surface of the core. (Despite the seeming favorability of this phenomenon, oil bleeding at this juncture usually denotes poor quality rocks of low permeability.) The saturations seen at the surface are different from those downhole. Figure 1 (Saturation changes that occur during coring and recovery with water-based coring fluid) illustrates the magnitude of saturation changes that occur from reservoir conditions to surface conditions when a core is taken with a water-base mud.

When oil or oil-base mud is used to core a well penetrating a homogeneous reservoir that is high enough upstructure to contain immobile interstitial water, no water will be added by the coring fluid. If excessive pressure differentials are avoided, the interstitial water will remain in place during both the coring and core recovery operations. In such a case the measured values of water saturation will approximate reservoir saturations. Figure 2 (Saturation changes that occur during coring and recovery with oil-based coring fluid) illustrates this phenomenon.

The pressure core barrel maintains reservoir pressure in the core during the trip to the surface, so that fluids that would otherwise be lost are maintained in the pore space and can subsequently be recovered in the laboratory test apparatus. Considerable research effort has been directed toward reducing core flushing during the coring process, and progress has been made. However, even pressure coring is likely to flush some of the fluids from the core during this process.

 

Damage to the Rock

One of the major objectives of coring is to recover representative, nondamaged samples of the reservoir. Damage to the core must be minimized. This is difficult to achieve with the percussion sidewall coring procedure where the core is subjected to high-impact stress as the hollow projectile is fired into the formation from an explosive charge.

Selection of Coring Fluid

Coring fluids can be divided into two major categories that relate to the filtrate lost: water-base muds (which tend to flush the core with water) and oil-base muds (which tend to flush the core with oil). Other less frequently used coring fluids include both water-in-oil or oil-in-water emulsions, gas or air, and foam. The latter is now used successfully in special applications. Common fluids used and filtrate loss are presented in Table 1., below.

Compatibility with Coring Objective

Coring fluids must be compatible with the objectives of the core analysis program. For example, if the specific value of reservoir water saturation is sought, no water should be added to the core. Locating gas-oil or oil-water contacts requires that no oil be added to the core. Oil-base mud filtrate flushes the gas zone, the oil zone, and any water zone present, and produces similar core residual oil saturations for all three zones.

Coring fluids	Filtrate	Effect on core saturations
		Water	Hydrocarbons
Water loss fluids
Water-base	Water	Increased	Decreased1
Oil emulsion	Water	Increased	Decreased
Foam*	*	*	*
Oil loss fluids
Oil base	Oil	No change2	Replaced
Inverted oil	Oil	No change2, 3	Replaced
emulsion
Gas loss fluids
Gas (hydrocarbon)	Gas	No change2,4	Replaced
Air	Uncertain	Uncertain5	Decreased

* Data indicate that foam that is properly formulated may exhibit what is essentially a zero water loss.

1. Saturations are decreased in hydrocarbon-productive zones. In water-flushed zones that contain residual hydrocarbons, the hydrocarbon is at residual and should remain so.

2. Water saturation should be unchanged if it is at irreducible (immobile) saturation; otherwise, water saturation.

3. These muds may contain water. Loss of whole mud in high permeability rock can increase water saturation.

4. Frictional heat may evaporate water from core.

5. Water saturations are erratic, depending on heat, condition of the hole and the agent that is mixed with air.

Table 1. Coring fluids, filtrates, and saturation alteration effects

Water-Base and Oil-Base Fluids

Figure 1 (Water saturation: oil-base and water-base coring fluids) illustrates core analysis water saturations as determined from cores cut with oil-base and water-base muds. Water in excess of the reservoir value exists in cores cut with water-base mud. A saturation approaching the reservoir value is observed in cores that come from above the transition zone and that have been cut with an oil-base fluid. Note that in the transition zone — the zone where the water saturation changes rapidly from 1000/0 to the minimum interstitial water saturation — the water phase is mobile. In most cases the water saturation is reduced by flushing with oil filtrate during the coring process. In some cases water within the transition zone will be flushed to the minimum saturation value; under such conditions, when the core extends into the water leg, it will be impossible to pick the oil-water contact.

 

Foam

Foam coring fluids are now receiving considerable attention. They offer the advantages of allowing a low coring fluid pressure at the formation face: in addition, preliminary data suggest that minimal or no invasion of the foam into the core occurs. Unlike other coring fluids, which remain in circulation during the operation, coring with foam is a once-through process. Foam is generated, then vented at the surface after a one-time use. This fluid has been used in both conventional coring and in the recovery of pressure cores, as discussed by Sparks (1982). The technology of foam coring requires that the process be monitored by computer and variables adjusted to assure proper quality foam during coring.