Recent laboratory studies investigating production-restricting formation damage provide constructive data that support the acute water-sensitive nature of these reservoirs and the importance of maintaining excellent fluid loss control. This is especially important when water-base drill-in fluids are used. The tests emphasize the importance of pretest preparation of core samples, which was shown to be essential in reducing formation damage in tight reservoirs. Further, laboratory investigations confirm that ultrafine material generated during the preparation of core plugs could propagate artificial fines migration; therefore, strict pretest cleaning procedures are critical to minimize artificial damage.

RDF formulation challenges

Formation damage reduces formation permeability and represents one of the most daunting problems in tight gas reservoirs. Reduced permeability restricts production and access to potential reserves. The primary contributing factors of formation damage include fluid invasion into the reservoir, the blocking of pores and fractures, and changes in water saturation.

This thin-section photomicrography of a tight gas reservoir shows both interparticle pores and oversized pores. Pores (shown in blue) are poorly connected. (Images courtesy of Schlumberger)

Low in situ permeability to gas, usually less than 0.50 mD, is intrinsic to tight gas reservoirs, which possess low porosity with pores that are typically poorly connected and highly reactive to water saturation. Most tight gas reservoirs have low or near irreducible water saturations near the well bore. Even a minimal decline in permeability can hinder production. A tight gas reservoir with permeability reduced by only 0.35 mD from an initial value of 0.5 mD effectively has lost 60% of its original permeability. Thus minimal changes in water saturation also affect permeability.

Tight gas reservoirs also present challenges in the design of RDF systems, including fluid loss control, fines migration, and mud solids invasion into the formation. Fluid loss control is a critical element in designing RDF systems. Priority is placed on optimizing bridging particle distribution to control fluid loss and likewise restrict solids invasion into pores, especially into fractures that are vital fluid-flow channels in tight gas reservoirs.

To design drilling fluids that would minimize formation damage potential, it is important to first underst and or evaluate the composition, structure, pore system, and deformation of reservoir rocks. Typically, these studies are conducted by observation using a petrographic microscope, XRD analysis, and SEM analysis among others.

Specific attention is given to the pore and fracture systems, including the relationship of pore to pore, pore to fracture, and fracture to fracture. These pores and fractures are the flow channels through which the gas must travel between the reservoir and the well bore. It is important to study the connectivity of these open channels, the pore sizes, and the fracture widths because small materials such as clays, fines, or mud solids can block the flow channels. The addition of bridging materials in conjunction with fluid loss control agents also demonstrates a reduction in fluid loss. The proper distribution of the sized carbonates for bridging pore spaces is a critical step to prevent mud solids and filtrate from invading the reservoir. Bridging particle sizes should be optimized according to pore-size distribution and fracture width as some tight gas reservoirs can have fairly large pores of 300 microns or greater that are not well connected.

A more natural mechanism for pore/fracture blocking is the presence of abundant clay or fines material. Clays can block flow channels through displacement or by a chemical reaction to water such as swelling. Clay inhibitors or oil-base fluids can be used to help minimize the effects of clay interaction.

An optimum bridging particle blend shows the target blend, which is related to pore size distribution and optimized blend of sized calcium carbonate.

Test sample preparation

Artificial formation damage can be attributed to the core preparation process. One source of artificial formation damage is the introduction of ultrafine material created during the core plug preparation process. Ultra-fine material can be forced into pore spaces at overbalanced pressures, causing artificial formation damage by blocking pore channels. When preparing a core plug for a gas return permeability test, the core should be cleaned by removing the fine dust material introduced from sawing the core. Cleaning helps prevent the artificial introduction of fines so the results more closely represent the particle sensitivity of the downhole formation.

For formation damage test preparation, careful attention must be given to the initial water saturation, which is vacuum-saturated in a synthetic or connate brine solution. Further, it is essential to centrifuge the core plug at high rpm to near irreducible water saturation to minimize the effect of residual water on permeability – a primary damage mechanism for tight gas reservoirs. Due to the high initial water saturation, this process helps reduce errors in test result interpretation.

Test protocol

Once a core plug has been properly cleaned and centrifuged, the sample is loaded into a permeameter for testing. Testing is conducted at reservoir temperature and elevated pressure to approach downhole conditions. Humidified nitrogen is flowed through the core plug in the production direction at reservoir temperature and increased pressures to establish a baseline permeability. Once a filter cake is deposited, overbalance pressure is applied for a predetermined period, during which filtration data are collected and recorded. Following the test fluid exposure phase, permeability is reestablished in much the same way as for the initial permeability phase.

Flow initiation pressure refers to the pressure required to initiate flow of gas or fluid through the reservoir rock after RDF exposure. Flow initiation pressure, which is calculated by subtracting the stable pressure from the maximum pressure when determining the final permeability, is recorded, with this data possibly indicating damage. Reductions in regained permeability often are associated with higher flow initiation pressures. Filtration values also can provide a clear indication of the extent of damage since higher fluid loss often is associated with lower regained permeability in tight gas reservoirs. All test results contribute to the overall interpretation of formation damage, but the most telling clue is the percent of regained permeability.

After vacuuming core plugs, pores are more visible and mostly clean of dust. Individual grains are clearly seen.

In one case study, test examples showed cores with higher filtration of around 12.8 mL, 204% pore volume having significantly lower regained permeability that cor- responded with a greater reduction in regained permeability by as much as 19.6%. The core samples with much lower filtration demonstrated high return permeability. Cases where return permeability values are >100% are most likely a result of reduced water saturations in the latter stages of the test. This is particularly true in tests conducted at very high temperatures where the core is more likely to "dry out." This effect is diminished in cores that have been centrifuged.

The tight fracture and pore spaces that become more saturated with water develop strong capillary forces that cannot be overcome easily. Situations such as this result in phase trapping. In many cases, the reservoir becomes permanently damaged with fluid invasion into the wellbore face, thereby reinforcing the critical need to use all available technology and procedures to minimize invasion at the onset.