Gokhan Coskuner

A New Process Combining Cyclic Steam Stimulation and Steam-Assisted Gravity Drainage : Hybrid SAGD

A new thermal recovery scheme is proposed that utilizes Steam-Assisted Gravity Drainage (SAGD) well pairs as well as Cyclic Steam Stimulation (CSS) wells placed in between the SAGD well pairs. The wells are operated in CSS mode until the steam chambers are in contact with each other and then switched to SAGD operation. It is shown that the new process recovers greater amounts of bitumen with lower injected steam in shorter operation time than is achieved with SAGD, Fast-SAGD and CSS.

Completion Operations in Low Permeability Deep Basin Gas Reservoirs: To Use or Not to Use Aqueous Fluids, That is the Question

Many tight gas formations are water-wet and undersaturated where the initial water saturation in the reservoir is less than the capillary equilibrium irreducible water saturation. Using aqueous-based stimulation and workover fluids causes water to be trapped in the near wellbore region, thereby significantly impairing the ability of gas to flow. Therefore, hydrocarbon fluids are better suited for completion operations in such reservoirs. Laboratory data revealing the sensitivity of one such formation to aqueous fluid invasion are discussed and actual field examples are provided in three different formations.

Drilling Induced Formation Damage of Horizontal Wells in Tight Gas Reservoirs

As the oil and gas industry matures and known reserves continue to be depleted, the focus moves towards more challenging environments. To help moderate the decline trend in reserves or to reverse it, the industry is expanding its exploration and development efforts to include horizons with permeabilities in the same range as common cement, that is, microdarcies. While horizontal wells are being used with increasing frequency in exploiting tight gas reservoirs, many questions have arisen as to the optimum practices to drill such wells. The experience of drilling horizontal wells in one of the deep basin tight gas reservoirs in Alberta is presented in this article. The initial results were below expectations. Consequently, a systematic study was undertaken to investigate the controllable factors that are in play during the course of drilling these wells. It was found that formation damage played a significant role in reducing the initial productivity. This was particularly true because all horizontal wells were completed in an open hole fashion where bypassing damage by perforation is usually not an option. The investigation into the formation damage in horizontal wells and its results are presented. The study led to using a new drill-in fluid which resulted in significantly reduced formation damage. Well tests conducted in the wells drilled with the new fluid appear to support the laboratory results. Finally, general guidelines are provided for selecting the most suitable drill-in fluid and implementing it in the field to minimize the horizontal well drilling formation damage in tight gas formations.

Production Optimization of Liquid Loading Gas Condensate Wells: A Case Study

Liquid production can be a serious problem in gas condensate wells nearing the end of their production life. As the pressure in the drainage area is depleted, the gas velocity in the production tubing falls below the critical rate resulting in inadequate energy to lift all the condensate out of the wellbore. The condensate migrates down the tubing and collects at the bottom of the completion increasing the bottom hole flowing pressure and, in many cases, killing the well. A similar liquid loading problem can be also encountered in low productivity gas condensate wells. This paper investigates the behaviour of gas condensate wells in a deep basin fractured sandstone reservoir in Alberta. Regardless of the initial well productivity, sooner or later, declining reservoir pressures and/or poor productivity cause wells to liquid load. The first and the cheapest solution is to produce these wells intermittently. Although such wells continue to flow, the liquid fallback still tends to increase the average flowing bottom hole pressure, thus reducing the production rate. The paper discusses the process of selecting the best candidates among such wells for the next level of intervention, which is the installation of plunger lift systems. As a result, 19 wells were equipped with plunger lifts and a significant production increase has been observed. The project has been a technical and economic success so far and is now being extended to the rest of the field.