The flow testing of oil and gas reservoirs is a critical operation used by operators in both openhole and cased hole applications. The information gained from openhole Drill Stem Tests (DST); permeability, flow rates, skin damage and water production is used to confirm well deliverability and justifies casing the well. Alternately many wells are production tested afier being cased to gather additional well information establishing reservoir limits and the presence of wellbore skin damage. In wells with large pay zones (horizontal), production tests are often used to selectively determine the source of well production, hydrocarbon or water, to allow remedial workovers.
Although well testing is common in nearly all reservoirs, the testing of sour gas wells and horizontal wells is still a significant challenge for operators and service companies alike. The testing ofsour wells has been very limited due to the concerns of H,S embrittlement of drillpipe and overall wellsite safety as sour gas is produced to surface. In most cases, without DST data, operators must rely on limited geological and openhole log evaluation to establish well deliverability allowing justification to case the well. In horizontal wells the challenge is to selectively test the horizontal section in the well and use this information to implement remedial stimulation to improve production.
This paper will review a new technology which uses an inflatable straddle packer tool deployed into vertical or horizontal wells using a "Coil-in-Coil" coiled tubing string configuration. An electrical conductor is located inside the inner string which allows for "real time" formation evaluation and tool operation. The inner coil string is used for all wellflow and stimulation operations, with the coil-in coil annulus utilized for circulation operations and packer element inflation. More importantly, the outside string also provides for pressure monitoring, flow containment and well control in the unlikely event of a failure of the inner string.
The testing of wells has been part of the oil and gas business since the first oil wells were drilled many, many years ago. After drilling a well to the target formation, many operators will undertake a flow test of the formation of interest using DST tools run back into the well on the drillpipe. This drillpipe, often empty, is positioned over the zone of interest and then the packer elements are expanded through pipe rotation or setdown weight. A valve in the DST tool is opened allowing formation fluids to enter the evacuated drillpipe and if adequate bottom hole pressure (BHP) and flow capacity is present, this results in well production to surface. If however the BHP is not sufficient, the well will continue to flow into the drillpipe until its hydrostatic pressure equals the reservoir pressure. The tools are then closed and recovered from the well and the produced fluid is measured and analyzed. In the early years of DST use, only well flow data was available. This information combined with openhole logs, was valuable in the confirmation that well potential was sufficient to warrant casing the well and pursuing a completion.