Successful High-Temperature/High-Pressure Well Testing From a Semisubmersible Drilling Rig
- A.R. Davidson (Hamilton Oil Co. Ltd.) | Gavin Prise (Hamilton Oil Co. Ltd.) | Clive French (French Oilfield Services)
- Document ID
- Society of Petroleum Engineers
- SPE Drilling & Completion
- Publication Date
- March 1993
- Document Type
- Journal Paper
- 7 - 13
- 1993. Society of Petroleum Engineers
- 1.6 Drilling Operations, 1.7.5 Well Control, 5.1.2 Faults and Fracture Characterisation, 4.2 Pipelines, Flowlines and Risers, 1.2 Wellbore Design, 1.3.2 Subsea Wellheads, 6.1.5 Human Resources, Competence and Training, 4.3.1 Hydrates, 1.7 Pressure Management, 4.1.5 Processing Equipment, 2.4.3 Sand/Solids Control, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 1.11 Drilling Fluids and Materials, 3.3.1 Production Logging, 1.10 Drilling Equipment, 2.2.2 Perforating, 5.6.4 Drillstem/Well Testing, 3 Production and Well Operations, 1.11.2 Drilling Fluid Selection and Formulation (Chemistry, Properties), 4.1.2 Separation and Treating
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In 1990, Hamilton Oil Co. Ltd. (HOC) drilled and tested three high-temperature/high-pressure (HTHP) wells from a semisubmersible drilling rig in the North Sea. This paper identifies the main pitfalls encountered when planning and implementing an HTHP well test with reference to three case histories. These cases demonstrate the benefits of defining a clear philosophy of safety and simplicity to test such wells successfully.
The U.K. government and rig-certifying authorities have tightened legislation on HTHP test design and implementation since Nov, 1988. U.K. Dept. of Trade and Industry federal guidelines laid out in Continental Shelf Operations Notice (CSON) 59 must be satisfied before permission is granted to test an HTHP well. CSON 59 defines an HTHP well as follows.
The undisturbed bottom hole temperature at prospective reservoir depth or total depth is greater than 300 degrees F and either the maximum anticipated pore pressure of any porous formation to be drilled through exceeds a hydrostatic gradient of 0.8 psi/ft or pressure control equipment with a rated working pressure in excess of 10,000 psig is required.
Several papers have highlighted the potential problems of testing HTHP wells from a floating drilling rig. In 1990, HOC drilled and tested three HTHP wells in the U.K. sector of the North Sea with a 15,000-psi semisubmersible drilling rig, Sonat Rather. The wells are called Wells X, Y, and Z throughout this text to maintain confidentiality. Problems encountered over the three-well test program are highlighted in the case histories. These cases demonstrate the benefits of defining and adopting a clear test procedure stressing safety and simplicity. The objective of this paper is to identify major pitfalls encountered when designing an HTHP test program. The general test philosophy discussed is relevant to all well-testing operations. philosophy discussed is relevant to all well-testing operations. The paper is a reference for the engineer designing an HTHP test.
HTHP Test Philosophy
The test design and philosophy adopted for HTHP testing is evolving. On the basis of its experience and data from other operating and service companies, HOC prepared a test program for Well X. As problems were encountered, test procedures and equipment were changed. A simple, standard HTHP test program was developed on the basis of the following principles: (1) invest time in personnel training, prejob planning, and equipment evaluation and selection; (2) systematically design the subsea and surface well-test package to correspond with the safety system; and (3) minimize the number and limit the use of downhole test tools.
Equipment and Procedures
The wells discussed here are typical of central and northern North Sea deep HTHP wells (see Tables 1 through 3). The test programs used on each well are operationally similar. The following sections briefly describe surface and downhole test components, which are important equipment evaluation and selection factors when designing an HTHP test.
Rig Well-Control Equipment. During test operations from a floating drilling rig, the subsea blowout preventer (BOP) pipe rams are shut around the subsea test tree (SSTT). This permits annular-pressure-operated downhole tools to function and annulus pressure to be monitored. pressure to be monitored. The elastomers in the BOP ram face have a 250 degrees F continuous temperature rating at 15,000-psi working pressure. This temperature can be exceeded when flow testing an HTHP well. In addition to normal maximum pressure calculations, the following points are considered before beginning testing: (1) estimate the points are considered before beginning testing: (1) estimate the most likely maximum flowing temperature with offset data and temperature modeling, (2) clearly define the maximum allowable surface-flowing temperature during testing, and (3) establish both the certified working pressure and temperature ratings of all components in the rig well-control system.
Subsea and Surface Well-Testing Package. Fig. 1 shows subsea and surface testing layout. This package design emphasizes both technical specifications and safety. Table 4 shows the technical specifications for the main system components, which reflect a fairly typical semisubmersible test package. Important points we considered follow: 1. Establish the certified working pressures and temperatures of all components. 2. Ensure that elastomer seals in the test system are of suitable specifications: they perform at high and low temperatures, are not susceptible to explosive decompression, and are compatible with anticipated produced fluids. 3. Use a metal/metal seal flowline from the flowhead to the choke manifold and from the choke manifold to the heater high-pressure side. This minimizes the number of elastomer seals exposed to extreme pressure and temperature. pressure and temperature. 4. Run a surface-readout temperature gauge as part of the SSTT package to monitor the temperature at the BOP ram face and ensure operation within the temperature limits of the system. 5. Ensure that high-pressure chemical injection points are situated at the SSTT and upstream of the choke manifold. 6. Perform a hazard and operability study of the test package, which includes the following. A. The Safety Analysis Checklist determines safety requirements for each segment of the system. B. The Safety Analysis Table defines the control and preventive actions necessary to safeguard each component and the system as a whole. C. The Safety Analysis Function Evaluation (SAFE) chart is an event/response matrix defining component interaction in the safety system. D. Nodal analysis on the complete test package and rig relief system at flow rates estimated for the well ensures adequate capacity. E. Permanent installation of an adequate welded relief manifold system to accommodate worst-case venting requirements will avert unsafe high-rate venting through temporary lines. F. Positioning the test choke manifold in the test area will facilitate venting.
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