Summary 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. Introduction 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:invest time in personnel training, prejob planning, and equipment evaluation and selection;systematically design the subsea and surface well-test package to correspond with the safety system; andminimize 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:estimate the most likely maximum flowing temperature with offset data and temperature modeling,clearly define the maximum allowable surface-flowing temperature during testing, andestablish 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:Establish the certified working pressures and temperatures of all components.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.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.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.Ensure that high-pressure chemical injection points are situated at the SSTT and upstream of the choke manifold.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. SPEDC P. 7

AUSTRACT This paper presents an oveIView of how the Completion performance on Rawnspurn North Development (RND) hilS heen dranliltically improved resulting in significant savings in well costs. With rcl'erence to performance statistics. four KL' Y aspects are reviL'wed. These arc the Completions Team, the Design Optimisation. the l'rocedural Optimisation and the Performance Optimisation.

This paper demonstrates how good transient well test data can be successfully obtained from shallow, high rate, gas production wells. Downhole shut-in has been reliably achieved on wells producing up to 82 MMSCF/D. The innovative use of standard completion equipment in testing these wells has made a valuable contribution to quality data acquisition and has been of great benefit in predicting long term production performance. INTRODUCTION Engineers continue to be faced with new challenges in the field of well testing. Many problems are solved by designing new test tools. However, in some cases solutions can be found by enhancing existing tools for use in new applications. Hamilton Oil Company Ltd (HOC) have successfully performed a number of well tests on some shallow gas wells. The problem faced was obtaining high quality pressure transient test data from wells in a relatively low pressure, highly permeable gas reservoir. Conventional downhole shut-in tools were found to unacceptably limit the production flowrate and hence the reservoir drawdown. Large diameter tubing with minimum restrictions and downhole shut-in were required. HOC identified the novel technique of using a large diameter, deep-set surface controlled tubing retrievable subsurface safety valve (TRSV) for the dual purpose of safety and downhole shut-in. HOC worked with a world-wide well servicing company to increase the depth setting capability of a conventional TRSV, which is normally used in production well completions. This paper provides a reference for the engineer designing a shallow high rate gas well test. Details of the test objectives and the various test string designs are given. Design and modifications to the TRSV for this specific application are discussed. Test results from successful case histories are presented. TEST OBJECTIVES A total of six welltests were performed. The objectives of these welltests were as follows:Perform testing operations in a safe and cost effective manner.Determine permeability-thickness, skin, reservoir pressure and reservoir boundary effects.Obtain representative reservoir ffuid samples.Establish whether there was potential for sand production or water coning during high rate gas flow. In order to fulfil these objectives, both high gas flowrates and downhole shut-in are required as part of the welltest programme. CONVENTIONAL TEST STRING DESIGNS Standard DST String A standard DST tool string consists of a number of annulus pressure operated downhole test tools as shown in Figure 1. This string design provides the following main features:Downhole shut-in to minimise well-bore storage effects during transient pressure build-up tests.A mechanical barrier for tubing pressure testing or downhole shut-in, in the event of an emergency.A simple means of circulating for well killing. The main disadvantage of this test string is its limited bore. Standard test tools, as shown in Figure 1, have an inside diameter of 2.25 in. In gas wells, this restriction causes very severe pressure drops when flowing at high rates with low bottom-hole pressures. The vertical lift performance of this test string was modelled on two independent computer models for Test NO.1.

BP Exploration, M.J. Cropper, DDPS, and G.J. Prise, EGIS cOPYf@t 1996 OFFSHORE TECHNOLOGY CONFERENCE mis pg.sf.a.pqamd for preeanmtica at me Ofkhore Techmdogy Ccmfersme neld u! wslon, Texas, 0-9 May 1936. The paper was selactad fw presentaticm by the OTC Prqr8MMe CGiIVIIIttW Iollowing re%iew 01 infcmnalbn wuahad w(thin an attavect submitted by the aumors. Contents 01 the papar as presenled have not been raviewed b Ihe K OffshOfa Tscfwwlogy COnleremx and are Subpsl 10 cormcllcm by the aul Ors. The material as fxeeamlad doaa not nac4ssarily reflect any pOSitiOn of the Offshore Technology C2antererw of Ita offkers. Pe~isWO m copy Is reetrklad to an abstrscl 01 not more than 3X3 words. Illuatratkma may not be copisd The ebstracf should confaln wspic wus aclmowlaclgamem of tiers and by whom Ihe papar was prasented. AbstractThe paper provides the Well Engineer/Manager with an overview of the basis of design for Foinaven wells; outlines the contracting strategy adopted for Well Construction; presents a summarised operational programme; and highlights some of the early lessons learned on this fast-track frontier project,