WELL CONTROL / INTERVENTION

How HTHP completions differ from the "norm"

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

Bob Moe and Carl Johnson, Oil Technology Services, Inc., Houston, Texas

oday’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°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°F BHTs – 300°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°F are not uncommon, and 400°F is attainable. A recent project saw measured BHTs of 350°F translated to 300°F at the surface on a 19,000-ft well produced at 90 MMcfd. Another high-rate well registered 360°F at the surface based on 450°F BHT.

New completion techniques, which allow wells to flow at increasingly higher rates without damaging the near-wellbore 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. 1¹ and 2² 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

Fig. 1. Data from NKK.	Fig. 2. Data from 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 H₂S. Weight-loss corrosion (often manifesting itself as a result of significant CO₂ 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.

Buckling and bending of the inner strings (tubing and production casing) are aggravated by high BHTs being brought to the surface. Connection leaks, permanently corkscrewed pipe and reduced length for acceptable tools can result.

Multiple casing strings, with essentially incompressible liquids between them, react to producing temperatures by attempting to expand the liquid. When the liquids are trapped by casing or cement, the attempted expansion results in annular pressure buildup (APB). Deepwater wells are likely to be more vulnerable to APB because of the cold seafloor temperatures at installation, in contrast to elevated temperatures during production. The pressure increase can be significant and has been known to fail otherwise-competent casing strings.

Temperature profiles can be easily and quickly modeled to simulate static, flowing, circulating and stimulation conditions. By anticipating temperature levels up and down the hole, the well designer can properly account for the impact of heat brought up from the reservoir. Ignoring temperature effects on the materials utilized in well construction will almost certainly lead to an HTHP well failure.

Environment

Acid gases, H₂S and CO₂, have severe cracking and weight-loss consequences when encountered in significant concentrations. H₂S should be reckoned with whenever it is detected, and sour-service measures should be implemented whenever concentrations greater than 0.05-psi partial pressure are encountered. NACE Standard MR0175 contains valuable guidelines for determining when sour-service material should be utilized. Temperature and reservoir fluids must be matched to the proper material or the operator can spend a bundle on shiny pipe and have it degrade in a hurry. Unfortunately, there is no clear-cut answer; each well must be designed based on its unique environment.

Concentrations of CO₂ as low as 30-psi partial pressure can present severe pitting and weight-loss corrosion. CO₂ corrosion is often associated with the presence of water – the combination yielding carbonic acid. The effect of CO₂ on the corrosion rate of 13 Cr stainless steel is shown in Fig. 3.³ The potent acid can attack even the most expensive alloys under the right temperature / pressure conditions. High chlorides in the formation of interest can result in similarly disastrous chloride stress cracking. Ironically, some of the most-expensive austenitic alloys are the most vulnerable to chloride stress cracking attack.

Fig. 3. Corrosion rate from CO2.

Unfortunately for the completion engineer, the environmental factors can combine and the combination is worse than each of the maladies individually. Although a number of HTHP fields have been successfully produced with chemical inhibition, proper matching of CRA to the environment fluids is generally the most-economical equipment solution.

Whenever feasible, a sample of the reservoir fluids should be obtained and analyzed. In doing so, the environment-to-material matching exercise is much easier, and the final completion is much more cost efficient.

Equipment

Once temperature, pressure and reservoir environmental conditions have been defined, well design / completion specifics become much more straightforward. Sour service designs have long utilized lower grades such as L80, but stronger steel grades such as T95, C100 and C110 contain specially formulated chemistries and have undergone controlled heat treatment and processing to allow them to resist cracking in many HTHP-well conditions. On a practical basis, temperature dictates where high-strength steel grades such as P110 and Q125 can be utilized in sour service. NACE Standard MR0175 provides minimum, sour-service temperatures of 175°F for P110 and 225°F for Q125. Although a big help to the well designer, they are still subject to weight-loss corrosion. To effectively tackle wellbore geometry requiring high-yield-strength tubulars at lower temperatures, CRA equipment is available to the well planner.

Wellhead equipment is subject to pressure derating in service above 300°F and shares the problems associated with accelerated corrosion of tubulars. Wellheads and trees have successfully utilized CRAs to maintain seal integrity. Cladding techniques (weld clad, HIP) have evolved to the state that entire valve bodies can be protected from the producing environment by a thin layer of CRA material applied to the valve’s inside surface. Again, a definition of the produced fluid will greatly aid in wellhead design considerations.

HTHP wells prolific enough to merit completion equipment are, by definition, high-rate wells. High rates produced through relatively small diameter tubulars result in erosion / corrosion and continuous loss of surface layers during the corrosion process. The material being corroded / eroded regulates the race between erosion / corrosion and pacification of the exposed surface. "Speed limits" for common oilfield alloys are shown in Table 2.

Connections

With the committed investment of high-cost steel or CRA in every joint of tubing or production casing, it is false economy to scrimp on the treaded ends. For HTHP wells, use of metal-to-metal seals with threaded and coupled connections (MTC) is the generic recommendation. If MTC connections are not compatible with completion geometry, some slimline, high-performance (SLH) threads with metal-to-metal seals may have a role – but flush joints should be limited to drilling liners.

A variety of testing / qualification strategies have been implemented to assure the user that thread designers’ connection performance claims are valid. ISO Draft 13679 is currently providing comprehensive guidance for connection evaluation. If strictly adhered to, this standard can supply the confidence needed to include a candidate thread in an HTHP well.

Packer Fluid

A variety of fluids have served as packer fluids in the tubing-production casing annulus, as shown below.

1. Packer fluids built from heavy-weight muds resulting from the latter stages of drilling are among the worst. Segregation of these muds can result in 35-ppg barite at the bottom of the annulus and 8.4-ppg water near the top. Obviously, this can result in severe sticking of both the tubing and packer. Such segregation will also make chemical corrosion treatment very difficult. If chrome tubulars are used, barite contact with the tubing has led to corrosive pitting, resulting in expensive repairs.
2. High chloride brines, such as calcium chloride, sodium bromide, sodium chloride and the like, can set up chloride stress cracking. If exposed to H₂S and CO₂, fluid pH can drop and ferric chloride – an extremely aggressive acid – can be formed.
3. The least expensive packer fluid that we have dealt with is fresh water with caustic added to form "11pH freshwater." Besides being cheaper, it does not require addition of biocides or oxygen scavengers. Contact with the producing formation may not be advisable.
4. Oil (diesel) or synthetic oil with a nitrogen blanket provides a corrosion-resistant medium sealed by several thousand feet of N₂. The oil column has an affinity for acid gases and provides the additional benefit of absorbing limited quantities of H₂S or CO₂.

The packer fluid must be matched to the alloy of the tubulars and accessories; and the production-tubing alloy must be matched to the producing environment. In addition, formation effects must also be taken into account, should packer fluid come in contact with the producing perforations.

Conclusions

So what’s the big deal? Temperature, pressure, environment, corrosive effects, APB potential, tubular material and end finish are the big deal. They are all critical factors in the design of any successful HTHP well.

The economically gainful completion of HTHP wells rests on the age-old axiom, "knowledge is power." Temperature and pressure profiles can be anticipated, and environmental conditions can be thoroughly analyzed. APB effects can be accurately calculated and material selection can be accomplished given accurate produced fluid specs. With proper planning, the combined effect of all downhole conditions can be reckoned with and today’s technology can be brought to bear on virtually any reservoir that can be penetrated with a drill bit. Therefore, what’s the answer? Consider and engineer all these factors, and plan, plan, plan.

Literature Cited

¹ NKK Products Bulletin.

² Murali, J., G. L. Boswell and R. R. Shulz, "Selection and application of stainless steel tubulars for a deep hot gas well," Oil and Gas Journal, Aug. 1, 1983, pp. 94-99.

³ CabVal Products Bulletin.

⁴ Ikeda, A. et al., "Introduction of a new dynamic field tester and preliminary results on flow effects on CO₂ corrosion," paper No. 48, NACE Corrosion 92.

The authors
	George Robert "Bob" Moe, P.E., VP-engineering, Oil Technology Services, Inc., (OTS), earned a BS in CE in 1975 from South Dakota School of Mines and Technology. His senior consultant responsibilities with OTS include quality assurance, systems management and design for drilling / completion / production of technically complex wells. His 20 years of experience with a major producer include quality assurance in manufacture of equipment for high-pressure / sour-gas production, drilling / subsurface operations, and major project planning / scheduling / coordination.
	Carl K. Johnson, a consultant with Oil Technology Services, Inc., obtained a BS in PE from Marietta College in 1967. His responsibilities at OTS include systems management and design for drilling, completion and production of technically complex wells. His 30-plus years of experience with various major oil / gas companies includes extensive operational / engineering work in all phases of oil / gas production, and multi-functional experience, such as special project management and systems re-engineering.