How HTHP completions differ from the "norm"

World Oil, Jan, 2001 by Bob Moe, Carl Johnson

Downhole/wellhead conditions under high temperatures and pressures add more-severe operating conditions than "conventional" well equipment is designed for. But proven solutions are available with proper planning

Today's deep drilling ventures are harnessing an impressive array of technological tools to explore deeper, geopressured formations accompanied by high mud weights and vexing high temperatures. Yesterday's challenge on exploratory wells was to obtain an electric log and get off the job before a well-control situation tilted prospect economics. This article points out the factors to be considered if the oil/gas operator wants to do more than look and see. What should he be prepared for? What is different about making a producer out of that deep, hot hole? What points need to be addressed to avoid turning that potentially high-rate dream into a completion engineer's nightmare?

INTRODUCTION

Conventional well design/engineering practices have served the industry in a satisfactory manner for years and allowed discovery and development wells alike to be completed for production. An operator with a healthy stock of API tubulars needed only to pull together the various packers, nipples and safety valves to cover his needs for most installations. Today, several factors have been altered: 1) The "available" equipment stock is no longer available. Lead times for procuring heavy-walled tubulars and high-pressure accessories are measured in months or even years, not days or weeks; 2) Equipment required to successfully produce many of today's discovery wells pushes the envelope of current design and manufacturing practices; and 3) Due to advances in 3-D seismic technology, drilling engineering and field practices, the number of deep producing wells has steadily risen.

The single, most-valuable guidance toward success with high-temperature, high-pressure (HTHP) wells, as gleaned by the authors' combined 50 years of drilling/completion experience, is planning. The engineer must recognize all of what the formation can bring to bear and design a solution for the combined effect. The investment in planning and engineering represents a pittance compared to the millions of dollars spent annually trying to get out of an operational jam or a well-control situation.

What is an HTHP well? We are unaware of a universally accepted definition of HTHP, but many operators consider any well with a bottomhole temperature (BHT) greater than 300[degrees]F and a surface shut-in pressure greater than 10,000 psi as an HTHP well. Some could define a deep well as any well deeper than 10,000 ft. Wells are drilled today in excess of 20,000 ft on a regular, if not routine, basis. On the other hand-- to those accustomed to drilling in regions with 150[degrees]F BHTs--300[degrees]F may be a hot well. Therefore, rather than a numerical limit, HTHP measures should be triggered by parameters unfamiliar to the operator. This will vary with operator experience and technological expertise.

TEMPERATURE

In many conventional casing designs, the impact of temperature is not even taken into account. The cumulative effects of elevated production temperatures can redefine the completion strategy. High temperatures are not limited to the bottom of the hole. HTHP wells with measured wellhead temperatures in excess of 300[degrees]F are not uncommon, and 400[degrees]F is attainable. A recent project saw measured BHTs of 350[degrees]F translated to 300[degrees]F at the surface on a 19,000-ft well produced at 90 MMcfd. Another highrate well registered 360[degrees]F at the surface based on 450[degrees]F BHT.

New completion techniques, which allow wells to flow at increasingly higher rates without damaging the near-well-bore area, are raising not only productivity but also wellhead temperatures. Higher rates bring high temperatures to the surface, with liquid being a more-efficient temperature carrier than gas. Water present in the flow stream or annuli also assists in transferring heat up the hole.

Elevated temperature can have a dramatic effect on materials. Yield strength is reduced as much as 10% in some HTHPs. Chrome and nickel have been added to corrosion-resistant alloys (CRAs) and have provided solutions to many hot-well challenges. Because many CRAs are anisotropic (yield strength not the same in all directions), the net strength reduction may be magnified and even doubled in hoop (burst) and radial directions. The nominal yield strength rating will no longer apply once well temperatures are taken into account. To illustrate this effect, Figs. 1 [1] and 2 [2] show reduced ratio of yield at well temperature to yield at room temperature. Note that, in the case of 22 Cr, this reduction can be as much as 25%, according to Murali, et al. [2]

High temperatures accelerate many chemical reactions, including corrosion. The two types of reactions commonly accounted for are stress cracking and weight-loss corrosion. Cracking failures are sudden, catastrophic and generally associated with high chloride content or [H.sub.2]S. Weight-loss corrosion (often manifesting itself as a result of significant [CO.sub.2] content) can be rapid at high temperature, especially if the material is not matched to the environment. Either type can lead to well-control concerns and even loss of a producing well.