Arkwright is a 50 × 106BBL oil field located within a single Forties Sandstone Member turbidite ‘channel’ system. Arkwright was discovered in 1990 and developed in 1996. Earlier start-up was precluded by reservoir risk and lack of export pipeline capacity. Reservoir definition improved after acquiring a 3D survey and applying imaging and attribute studies. This, combined with subsurface analogue, core, and carbon, oxygen and strontium isotopic studies, improved understanding of reservoir architecture and connectivity. Geostatistical techniques were used to quantify the STOIIP. The main risks identified were the absence of aquifer support, and possible vertical and lateral baffling. As these could not be tested by appraisal drilling it was decided to commence development.Low-cost, two-well development options were considered and rejected because of the subsurface risk. Without guaranteed aquifer support, the productivity from early sub-bubble point flow would be lost waiting for injection support to be added. Risk-weighting highlighted the advantage of initial expenditure to safeguard the project, and so a third initial production well was planned, in a location suitable for conversion to injection.Predicted rates were increased and the impact of lateral baffling minimized by drilling deviated producers on opposite sides of the structure, and not reusing the discovery well. Costs were reduced by using a drilling centre outside the field. The perforation strategy ensures drainage above and below potentially sealing abandonment shales, and facilitates future zonal isolation. Communication within the reservoir was tested at start-up with an interference test.

We describe the Period detection and Identification Pipeline Suite (PIPS) — a new, fast, and statistically robust platform for period detection and analysis of astrophysical time-series data. PIPSis an open-source Python package that provides various pre-implemented methods and a customisable framework for automated, robust period measurements with principled uncertainties and statistical significance calculations. In addition to detailing the general algorithm that underlies PIPS, this paper discusses one of PIPS’ central and novel features, the Fourier-likelihood periodogram, and compares its performance to existing methods. The resulting improved performance implies that one can construct deeper, larger, and more reliable sets of derived properties from various observations, including all-sky surveys. We present a comprehensive validation of PIPSagainst artificially generated data, which demonstrates the reliable performance of our algorithm for a class of periodic variable stars (RR Lyrae stars).

This paper presents an overview of the evolution of design requirements for wellhead housing running tools necessitated by the development of wellhead interface systems to overcome the higher static and fatigue loadings generated by harsher environments and deeper water. A brief history of the progression of wellhead designs is also presented in conjunction with their relevant running tools. A review of field operations for a new wellhead interface design with tapered sockets is presented along with the design of a tool that seats the double taper sockets [9].

On offshore platform and jackup surface wellhead completions, there is the potential for leakage from the high pressure production tubing and casing strings into the low pressure outer casing string, or from poor cementing jobs. Historically, these completions maintain the capability of regularly monitoring wellhead annulus pressure so that appropriate action can be taken should a leak be detected. In the past, subsea completions have been oil producers, however, gas production, extreme reservoir pressures, and deeper waters are becoming commonplace. Although subsea wellhead technology and reliability have significantly improved with the introduction of the metal-to-metal sealing system, the potential for annulus pressure buildup still exists. Up to the present, the ability to monitor pressure beyond the first casing string has been virtually non-existent. Such monitoring would require penetration of the wellhead housing, a very hazardous practice. Conversely, non intrusive sensortechnology will be a significant industry advancement. It provides a means of measuring pressure through several inches of steel housing wall thickness. This paper describes the design, development, testing, and application of non intrusive sensor technology for pressure measurement in subsea wellheads and production trees. The data and test results define and describe the phenomenon of "inverse magnetostriction". This phenomenon allows agnetic sensors to non intrusively penetrate three to four inches of steel in a subsea wellhead housing and measure annulus pressure from less than 30 psi to more than 15,000psi. In addition, test data, charts, and graphs illustrate the sensor's capability of differentiating between pressure, tension, compression, and bending stress imposed on the wellhead. The electronic interface description details how the data is obtained from the sensors, stored, and Iatertransmitted to existing control systems or to the user interface at the surface via an ROV. THE NEED FOR NON INTRUSIVE ANNULUS PRESSURE MONITORING Surface Capability To Monitor: Because hydrocarbons can gain entry into the casing by leaking past the downhole packers, seeping through threads on the pressurized production-tubing string, or leaking through the cement, it remains important to monitor wellhead annulus pressure. When pressure buildup is detected and determined to be unsafe, action can betaken relieve the pressure or kill the well if necessary. Monitoring pressure in the wellhead varies with the type of hookup. On some offshore facilities (i.e., jackup rigs), the surface wellhead with all the casing strings is suspended from the deck. In this type of arrangement, the innermost casing annulus is accessible, and all the annuluses can be monitored with standard pressure gages fixed to the casing spools and casing heads. With subsea satellite trees, only the innermost annulus pressure maybe monitored. This can be donethrougha separateannuluslinerunningbackto the platform and paralleling the flow line on the ocean floor [1]. Alternately, the annulus pressure maybe monitored through the flow line itself by closing the master valve to interrupt the flow and opening the crossover valve at the tree. Pressures To Expect: In the Gulf of Mexico, well pressure can be low enough to require pumping, or it may exceed 15,000 psi.