Completion Design and Implementation in Challenging HP/HT Wells in California
- D.E. Hahn (Adams Pearson Assocs. Inc.) | L.H. Burke (Adams Pearson Assocs. Inc.) | S.F. Mackenzie (Adams Pearson Assocs. Inc.) | K.H. Archibald (Anadarko Canada Corp.)
- Document ID
- Society of Petroleum Engineers
- SPE Drilling & Completion
- Publication Date
- December 2003
- Document Type
- Journal Paper
- 293 - 303
- 2003. Society of Petroleum Engineers
- 4.2.3 Materials and Corrosion, 1.6.9 Coring, Fishing, 2.2.2 Perforating, 4.3.1 Hydrates, 5.9.2 Geothermal Resources, 5.2.1 Phase Behavior and PVT Measurements, 2.4.3 Sand/Solids Control, 1.14.1 Casing Design, 4.6 Natural Gas, 5.2 Reservoir Fluid Dynamics, 1.7 Pressure Management, 2 Well Completion, 4.1.5 Processing Equipment, 1.6.11 Plugging and Abandonment, 5.1.2 Faults and Fracture Characterisation, 1.6 Drilling Operations, 3 Production and Well Operations, 1.8 Formation Damage, 4.2 Pipelines, Flowlines and Risers, 1.14 Casing and Cementing, 5.6.4 Drillstem/Well Testing, 2.2.3 Fluid Loss Control, 1.14.3 Cement Formulation (Chemistry, Properties), 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 2.7.1 Completion Fluids, 4.1.2 Separation and Treating, 1.10 Drilling Equipment, 1.7.5 Well Control, 4.1.4 Gas Processing, 1.11 Drilling Fluids and Materials
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As producing companies search for significant hydrocarbon resources, it has become necessary to pursue opportunities in frontier geologic horizons and geographic locations. This pursuit frequently results in encountering high-pressure/high-temperature (HP/HT) environments. The petroleum industry defines HP/HT wells as those exceeding 10,000 psi and 300°F.
Several companies have drilled into HP/HT horizons in the California San Joaquin basin in the past 30 years, but operations were generally halted because of equipment limitations or limited hydrocarbon indications. In late 1998, a significant gas flow was identified from the Temblor formation at depths lower than 17,100 ft, with geologic information indicating a potential Temblor sand gross thickness of up to 3,600 ft. The pressure design basis for subsequent wells assumed an estimated equivalent pore pressure of 16.9 lbm/gal. This information and other producing conditions indicated a potential bottomhole environment of 425°F and 18,000 psi. Produced fluids also indicated the presence of hydrogen sulfide (H2S), which, at these pressures, dictates sour service metallurgical specifications.
These potential, extreme well conditions require a very detailed completion engineering design, equipment qualification, rigorous planning, and precise field execution to achieve successful well completions. This paper details and discusses the well completion design basis and issues, equipment/perforating limitations and qualification tests, tubular stress and loading analyses, high-density completion-brine usage, and actual field operational experiences.
Numerous contingencies were planned in detail, some of which had to be implemented. The most significant contingency operation was a high-pressure coiled-tubing milling operation to clean out 2,500 ft of formation and perforating debris that plugged the tubing string.
The wells discussed in this paper are located approximately 50 miles northwest of Bakersfield, California, in the East Lost Hills field. The East Lost Hills field is situated in the southern end of the San Joaquin basin, which began evolving in the late Cretaceous and early Miocene. The basin is bounded to the north, east, and south primarily by the granitic rocks of the Sierra Batholith and Foothills belt and to the west by the San Andreas Fault. The primary objective of this drilling and appraisal program is the lower Miocene Temblor section (Zemorrian to Saucesian), a 3,600-ft-thick succession of interbedded sandstones and shales of bathyal origin. Thus far, wells have reached depths between 17,400 and 21,700 ft. Pore-pressure gradients at this depth are approximately 0.88 psi/ft, and reservoir temperatures are between 350 and 385°F.
The first well was drilled in 1998 and penetrated the Temblor sand section; however, upon reaching the zone of interest, unforeseen pore pressures resulted in an uncontrolled flow from the well. The surface flowing information obtained from this well (no shutin data) formed the basis for future well designs and equipment qualification requirements. Because of the high degree of uncertainty in all the actual well conditions, assumptions for the worstcase reservoir pressures and temperatures of a well drilled to a total depth of 20,000 ft had to be made for future well completion designs. The resultant maximums were extrapolated to be 18,000 psi and 425°F. In addition to these downhole static conditions, the initial design assumed a maximum dry-gas production of 40 MMscf/D and wet-gas production of 15 MMscf/D with a water/gas ratio (WGR) of 350 bbl/MMscf. These combined conditions, together with the fact that H2S and carbon dioxide (CO2) were present in the well effluents, approach the operating boundaries and limitations of many tubulars and completion equipment.
During the course of designing these initial wells, there was still significant uncertainty of the reservoir parameters and the actual resource size (productivity and reserves); thus, it was necessary to determine an optimal, cost-effective wellbore to efficiently and safely obtain production tests. Ideally, every well component should be able to operate at all assumed conditions without operating limits. This is not always a practical, pragmatic, or economic solution, with a large number of uncertainties, and in turn, the risks and equipment limitations need to be understood and rigorously managed. Another objective of the initial completion was to ultimately produce the well for a longer-term flow period, if at all possible, which would assist in the evaluation of the resource size and reveal possible production issues (e.g., corrosion). The longer-term development and exploitation of this exploration prospect may result in well designs that are significantly different than these initial wells once the precise nature of the producing and shut-in conditions are obtained.
To carry out completion and testing successfully within these very hostile conditions, it was recognized that a strong team of highly skilled and very competent individuals would be required. This project also emphasized the importance of positive interaction between each member of the well-construction, operations, and reservoir management groups. The designated team was very effective and instrumental in the successful design and cooperative implementation of several subsequent completions, each having its own technically challenging variations and issues.
Production Casing Selection
The final production casing string has significant implications for completion equipment selection; thus, it is very important that the casing selection incorporates all the completion considerations and limitations. Frequently, in normal applications, the primary factor considered is the burst of the casing compared to the maximum expected static internal pressure. Although this is important, there are numerous additional dynamic loads that need to be considered when designing the final production casing and liner strings to ensure that adequate safety factors are maintained.
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