This pepef was prepared fcf pmsomation et the SPE Annual Tschnic.al GantemncwJand Exhibition held in DaNM, U. S. A., octoh 22-25, 1995. Th!s paper was selected for presentation by an SPE Program Committee Ioltowing review of information contained in an abstmd submhled by the authors. Contents cd the paper, as presentsd, have nd bwn reiewed by the SodmtY of Petroleum Engineers and are subjed to cursdica ,py the authors. The material, as presented, does not necessarily ref ted an R%%::'R%G%2 Petroleum En~ineers, its otlicers, or nmnbers. Paperspresented at S publicatkm review by Edtirial Conmittsm of ths Soc4ety of Petroleum Enginsws Permission to CUFY K restricted to an chtred d not r-mm than 330 wards. Ilkmlfatbns K9y not be copied. The abstract shculd contain wnspiwot.ts acknosddgmm tot whue and by whun the papei was wesented. Wrhe Librwian, SPE, P. 0. Box S33B36. Rkhafd=n, TX 76C93-393S, U. S. A., lax 01-214-952-9435.Abstract:

Summary In some applications, complete separation of liquid and gas is not required, and it is sufficient to remove only a portion of the gas. One example is separation of gas from one well for raw gas lift of other wells. This can be done either on the surface or downhole The auger separator is a new device that was initially developed to fit inside production tubing, and so is an ultra-compact separator design. It differs from other separators in that it requires no complex controls or power to operate, and, for most applications, has a diameter of only a few inches. The multiphase fluid enters an auger section where the pitch of the stationary auger blade causes the flow to rotate. Centrifugal forces created by this rotation cause the liquid to flow along the outer wall with the gas flowing in the center. A portion of the gas is ported through a crossover to the annulus in downhole applications or to a gas line in surface applications. The downhole separator is placed by wireline in the tubing. The surface version is placed as a spool piece in the production line. Equations were developed to predict performance and were incorporated into a spreadsheet for ease of design. Laboratory tests were performed to validate the predictions and to explore various design details. Following successful lab testing, the prototype separator, which was 3-1/2 inches in diameter, was placed downhole inside 4-1/2" tubing. The separated gas was ported to the annulus through a gas lift mandrel. This test showed that the equipment could be placed in the well with wireline that downhole separation was feasible, and that the theoretical pressure drop calculations were accurate. Following this test, an 8-inch diameter auger separator was designed for separation of gas on the surface, as a full scale pilot test. This was placed in the production line from a well, and the separated gas was used to provide raw lift gas for other wells on the drillsite. These two field tests showed that partial separation was feasible with this device, and that the equations used for design were reasonable. The surface auger separator was left in place after the test, and continues to provide lift gas. This paper presents the concept, design equations, lab test results, and field test results of both a downhole and surface application. Other potential uses are also discussed. Introduction Conventional separators are normally large vessels with elaborate control systems to maintain levels. Those designs have evolved from applications where 100% separation is desired. However, there are many instances where a relatively dry gas will suffice, so that complete separation is not required. In those applications, much simpler and more compact designs are possible. One such application is raw gas lift, where some liquid carryover can be tolerated. By using a well on the drillsite as a source well, gas lift can be provided to other wells without the need for expensive gas supply lines or processing equipment. This greatly improves the economics for gas lift. The rough separation of gas can be done on the surface if the surface pressure of the supply well is high enough. But if the surface pressure is not high enough, this separation can be done downhole The advantage of downhole separation is that a higher gas pressure can be achieved if the gas is not subjected to the frictional and head pressure drops produced by the more viscous and dense liquid phase. This is avoided when the separated gas is allowed to flow up the annulus. The downhole application was conceived and developed first, and it was the small size required for installation in tubing that led to the compact installations that were later achieved on the surface. To be feasible, the downhole separator had to be compact enough to be installed and retrieved on wireline inside 4-1/2" tubing, require no power or complex controls, and have no moving parts. All of these attributes turned out to be attractive for surface separation as well. The device which we developed and describe below met all of those design goals.

A system for riser management has been developed and used, consisting of: 1) a variable buoyancy system, 2) hardware to hangoff a disconnected marine riser near the keel of a drillship, 3) a heave acceleration prediction capability, 4) instrumentation for monitoring heave acceleration and riser buoyancy, tension, pressure, vibrations, and inclination, and 5) a technique for making hang-off and disconnect decisions based on forecasts and real time vessel motion measurements.

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Introduction Since July 1976, crude oil from the Montrose Field in the North Sea has been offloaded via two single point moorings (SPM's) and two shuttle tankers. The production platform has no storage capacity and must therefore shut in production whenever a tanker is not moored and loading. Adverse weather conditions in the North Sea affect the tankers' ability to stay moored to the SPM and their ability to remoor, and are the major cause of offloading downtime. In September 1978, an in-house project was initiated to investigate ways to reduce the downtime without instituting major changes in the system. This paper discusses some of the major operational factors leading to downtime and describes steps taken in attempting to reduce it. These include periodic technical discussions with operations personnel and tanker Captains, which resulted in minor hardware modifications and computer simulation studies for predicting tanker responses in severe weather. 2. Offloading System Description The two buoys are of the catenary anchor leg mooring (CALM) type, and are situated approximately one mile from the Montrose production platform, in approximately 91 m (300 ft) of water. The field uses two dedicated 72,000 dwt tankers for offshore loading. The tankers self-moor to the buoy using a hydraulic double drum ropetraction winch mounted on the forecastle deck in the peak of the bow, with the rope running through a U-shaped rounded fair-lead. The winch can develop a holding capacity of r.38 × 106 Newtons (310,000 lbs). The hawser tension is measured by hydraulic load cells attached to the winch brakearms. The mooring hawser is a 107 m (350 ft) long, 170 mm diameter, double braidednylon rope. It is spliced into 122 m (400 ft) of size 12, eight-strand, polypropylene messenger rope. The end of the messenger rope has a knot turned in it to facilitate grapnel hook-up for mooring. A more complete description of the Montrose offloading system has been reported previously in Ref. 8.