Application of Heat Treatment to Enhance Permeability in Tight Gas Reservoirs
Authors: Jamaluddin A.K.M. , Bennion D.B. , Thomas F.B. , Ma T.Y. 
Published: March 2010

During the drilling and completion phases, the primary mechanisms of near-wellbore formation damage can be attributed to the following factors:pore throat constriction caused by clay swelling, deflocculating due to incompatible fluids or clay migration;water blocking resulting in a reduction in relative permeability to hydrocarbons;plugging with drill solids and mud products; andloading of the reservoir with drilling or completion fluids. In tight reservoirs, phase trapping and water-blocking are believed to be the primary causes of near-wellbore formation damage, resulting in very low productivity. Clay swelling and phase trapping in tight gas reservoirs during drilling and completion have long been identified as major problems. Preventive measures have been discussed in literature; however, prevention of clay damage and phase trapping is not always possible or effective and curative measures may then become necessary. Several curative methods have been attempted and presented in literature with mixed success.

A formation heat treatment (FHT) process has been developed in the last four years and initial field test results showed promise. The primary mechanisms of the FHT process are to vaporize blocked water, dehydrate clay-bound water, destroy clay lattices and possibly create micro fractures due to thermally induced stresses, with the objective of removing near-wellbore drilling induced skin damage.

The objective of this laboratory study was to evaluate the feasibility of applying the formation heat treatment process on cores taken from a tight gas reservoir. The results indicate that the FHT stimulation at 649 ° C resulted in a 210% improvement in permeability from the baseline undamaged value and 675% improvement from the damaged (water-trapped) value. The post FHT waterflooding of the core still showed 50% improvement in permeability from the baseline value and 275% more than the watertrapped value. Laboratory results along with the field logistics are presented in this paper.

Introduction

Formation damage can occur at any time during the history of a well-from the initial drilling and completion of the wellbore through to the depletion of the reservoir during production. Operations such as drilling, completion, workovers, and stimulation, which expose the formation to a foreign fluid, may cause formation damage because of adverse wellbore-fluid to formation interactions. Such damage is usually severe in horizontal wells, because of the longer exposure of the wellbore to the offending fluids(1 – 7). During the drilling and completion phases, the primary mechanisms of near-wellbore formation damage can be explained by the following factors:Pore throat constriction, caused either by clay swelling due to incompatible fluids or by clay migration,Water blocking due to reduction in relative permeability to hydrocarbon,Plugging with drill solids and mud products,Loading of the reservoir with drilling or completion fluids.

In tight gas reservoirs, formation damage, due to phase trapping and water blocking, has long been identified as a major problem. Preventive measures against this type of damage are not always possible or effective, and curative measures may then become necessary. Several curative methods have been attempted and presented in the literature(8–15).