Completion Practices and Techniques in Deep Gas Producers of the Delaware Basin
Authors: West E.R. , Lindsey H.E. 
Published: December 2007

Abstract
In the past 5 years more than 80 of the deepest wells in the world have been drilled below 20,000 ft in the Delaware basin of West Texas. Most of these wells have been tremendous gas producers and have required some extraordinary completion procedures. The main factors causing completion problems are depth, pressure, temperature, high producing rates, and extensive stimulation treatments. Pronounced changes in tubing length (as much as 22 ft within a few hours) are caused by temperature and pressure fluctuations that occur between treating and flowing. Presented are equations to calculate elongation and shortening, and a graph to calculate expansion. Described and discussed are a widely used typical completion as well as some newer completion practices. A recently developed well completion tool, the production "packer bore" receptacle, is described.

Introduction
In the past 5 years some of the deepest producing wells in the world have been completed in the Delaware basin of West Texas. More than 80 wells deeper than 20,000 ft, and another 50 ranging from 16,000 to 19,000 ft have been drilled.
Extreme depth, high pressure, high temperature, high production rates, and extensive stimulation treatments production rates, and extensive stimulation treatments present problems in completing these deep wells. Completions present problems in completing these deep wells. Completions at over 20,000 ft are not routine and demand extensive study to handle future delivery and re-entry requirements.

Large Acid Treatments
Usually, high-rate, high-pressure acid treatments make better wells in the Delaware basin. Most deep producing gas wells are treated in this manner. The pay zone porosity usually is distributed over 1,000 to 1,600 ft of porosity usually is distributed over 1,000 to 1,600 ft of lime or dolomite. Adequate treatments of each zone of porosity require relatively large amounts of acid. Optimum results usually are obtained with treatments totalling about 25,000 gal. However, some treatments have been made using over 200,000 gal.
To achieve a satisfactory penetration distance past the wellbore, the acid must be retarded and should be injected at relatively high rates. Retardation is extremely difficult at the temperatures (250 to 350F) encountered in deep wells. However, even with the difficulty experienced to date in retarding acid, amazing results have been obtained from treatments of deep wells.
High acid injection rates are almost a necessity to stimulate a hot, deep reservoir. Assume that a 1,500-ft section is perforated with only 50 holes. An injection rate of 25 bbl/min is required to allow 1/2 bbl/min/hole if all holes are open. A 1/2 -in. diameter perforation will pass 3 bbl/min with slightly over 400 psi differential pressure. If all 50 perforations happen to be open, approximately 150 bbl/min perforations happen to be open, approximately 150 bbl/min could be injected at 400 psi pressure drop across perforations. perforations. Injection rates of this magnitude are not physically possible even with the larger tubing sizes installed in most possible even with the larger tubing sizes installed in most deep completions; therefore, perforations should be kept to a minimum to assure adequate distribution of acid. Experience shows that, normally, no more than 25 percent of the perforations are open during the first part of percent of the perforations are open during the first part of a treatment.
Improvements are constantly being made in acid retardation. At present, retardation time is often insufficient. The current acid recommendation from most treatment service companies for deep, hot wells is a mixture of 15 percent hydrochloric acid and formic acid. Normally, 8 percent of the mixture is formic acid and 92 percent is a 15 percent mix of hydrochloric acid.

Large Production Flow Rates
Gas purchasers usually contract to buy gas from a deep well on the basis of 1 MMcf/D for each 8 Bscf of reserves. With reserves ranging from 100 to 200 Bscf/well, the daily producing rate can easily be 10 to 25 MMcf. Thus, an operator must design and install completion equipment adequate to supply these volumes.
Above-normal capacity often must be designed into the completion to compensate for "take or pay" gas contract. At original BHP, a gas well can deliver a given volume of gas with a minimum friction drop through the producing string. Future declines in pressure may mean the producing string. Future declines in pressure may mean the same production rate can be maintained only at the risk of higher friction loss in the tubing string. Thus, tubing strings also should be designed to permit continued high producing rates at lower formation pressures. producing rates at lower formation pressures.
JPT
P. 921