Abstract An expert system capable of diagnosing the potential of formation damage caused by clay swelling, fines migration, inorganic scale deposition, and organic scale precipitation was developed and implemented. In this manuscript, we present results for the expert modules pertaining to asphaltene precipitation and asphaltic sludging. These modules estimate heuristically the potential for asphaltene precipitation, and for asphaltene sludge due to acidizing.
Rules of thumb pertaining to asphaltene precipitation caused by solubility incompatibility between crude and solvent were collected. Membership functions to fuzzify these rules were constructed. The asphaltene module is capable of estimating the potential of asphaltene precipitation for a wide range of phase-behavior reservoir conditions, and for a much wider range of live and stock-tank crude compositions than what can normally be handled by a human expert. The acid sludge module makes its judgment based on factors such as acid strength, acid type, solvent preflush, iron control additives, Ferrous and Ferric ion concentrations, mutual solvent concentration, corrosion inhibitor type, and surfactant types used. A model has been formulated to predict the amount of asphaltene sludge that is likely to form as a consequence of crude-acid contact.
A graphical user interface using various templates for data input and modules output has been built to make the expert system user friendly. The expert modules have been validated using a range of field data. This expert system gives the advantage of automating the diagnosis process pertaining to formation damage.
Introduction Formation damage can be defined as any mechanism which tends to reduce the actual or relative permeability to oil or gas in the formation, and impedes the flow of fluids into or out of the wellbore, As a consequence, formation damage can be thought of as a zone of altered permeability extending radially from the wellbore to some radius inside the formation. Formation damage is caused by some movement of fluid either into or out of the formation. Wellbore fluids that are lost to the formation may not be compatible with the formation rock or formation fluids, or may carry damaging solids into the formation. Produced fluids themselves may damage the formation during production either by precipitating solids or changing the wettability or relative permeability near the wellbore. Some form of well test is normally used to determine the presence and severity of formation damage. There are many different types of well tests such as buildup tests, drawdown tests, multirate tests, deliverability tests, pulse tests, and injectivity tests. The methods for performing and analyzing the information from these tests can be very different, but all of these tests measure the pressure response of a well to some change in flow rate. Any deviation in the pressure response of the well from that which is predicted from Darcy's law or the diffusivity equation is treated as damage and is reported as a skin factor. The skin factor is a dimensionless number that can vary from zero for an undamaged well to + 10 or greater for a highly damaged well. In high-rate oil and gas wells, there can be some pressure drop in the formation due to turbulent flow. This will show up in the skin factor term, and must be accounted for to get the true value of skin. If damage is present, its severity may be evaluated by analyzing the results of a flow test or a transient pressure test.
Formation damage can occur during drilling, completion, workover, production, or injection operations. The following types of damage can occur:
Silts and Clays: A loss of permeability due to swelling or migration of native clays or introduced silts and clays that act to plug the pores of the formation rock.
Water Blocks: A temporary drop in the relative permeability to hydrocarbons due to an increase in water saturation in the near-wellbore region caused by the loss of a significant amount of water-based fluids into the formation.
Wettability Alteration: A change in the wettability of the formation in the near-wellbore region from its normally water-wet condition to a more oil-wet condition as a result of the adsorption of oil-wetting surfactants on the formation rock, especially from oil-based drilling fluids which-reduce the relative permeability to hydrocarbons.