As Operators are increasingly seeing the value of in-well monitoring in optimizing production and reducing interventions, Operators are demanding greater accuracy, reliabilty and timeliness of well information above what is available today. This study explores a new method of measuring temperatures in harsh downhole environments that aims to improve on some of the limitations of conventional distributed temperature sensing (DTS). Instead of using Raman backscatter signals to infer temperature, a calibrated fiber Bragg grating (FBG) array is used to measure the temperature. Bragg gratings have previously been deployed as temperature measuring devices, usually as discrete devices individually spliced in a cable. The cable design presented in this study reduces deployment costs compared to discrete Bragg gratings, and can also scale up to 1000 gratings. Additionally, an interrogation method has been developed for measuring the wavelengths of the FBG array. Traditional swept-wavelength interrogation techniques exist to measure FBG arrays, but they are typically limited to approximately 40 gratings. Like the cable, the interrogation method scales up to 1000 gratings at 1 meter grating spacing. Numerous system performance tests were conducted in a laboratory setting and in a simulated well environment. A prototype cable was deployed in a test well alongside a standard DTS cable. The cables were exposed to temperature cycling by circulating hot and cold fluid. Measurements produced by the two cables were recorded and analyzed. The prototype cable test results demonstrated that the grating cable is capable of higher resolution temperature measurement than conventional DTS. The prototype interrogator will be able to perform the measurement in less than 10 seconds, a fraction of the measurement time required by conventional DTS interrogation. Results from other tests have demonstrated the ability to perform well with long lead-in distances without losing accuracy. With this increased range, the interrogator can be located away from the wellhead and in offshore wells, above water.

As production from the Gippsland Basin in Bass Strait Australia passes the 30 year mark, the need to find innovative techniques to maximise production from this world class maturing basin is a principle priority for the operator. To address this issue, Esso Australia, on behalf of the 50: 50 joint venture with BHP, recently embarked on a concentrated program to trial and evaluate several new technologies being developed by industry. This paper discusses several technologies that were employed to increase production, enhance reservoir recovery and improve well integrity. Varying degrees of success were achieved during these trials and the successes, failures and lessons learned will be outlined. The technologies discussed include:Scab liners with inflatable packers set through tubing in horizontal wells to isolate water/gas production;Gas and water shut off techniques utilising polymer technology;Wellhead leak sealing technology using differential pressure-set coagulating polymers;Wirelineless completions using expendable plugs and perforating gun hanger systems on space limited platforms (during infill drilling operations);Through-tubing deep penetration perforating charges used to stimulate production from wells with extensive near wellbore damage; andMini-fracturing gas stimulation technology used on poor performing reservoirs. The high level of mechanical success combined with encouraging reservoir success in some instances is promoting a continued search for further production enhancing techniques. Introduction Esso/BHPP's operations in Bass Strait, South Eastern Australia, include 16 production platforms, five sub-sea completions and two single mono-towers (Fig. 1). From these facilities there are 364 wells, the majority being oil and/or gas producers with the remainder injecting for reservoir management. Since production commenced from the Gippsland Basin in 1969 with the installation of the Barracouta platform, significant ongoing drilling and workover activities have enhanced and maintained production levels. Until the mid to late 1990s, traditional tubing pull, mechanical isolation and cement squeeze techniques have yielded high levels of mechanical and reservoir success with strong workover economics. An ever declining list of high quality opportunities, as evaluated using traditional techniques, made it necessary to embark on a search for technologies that would continue to achieve mechanical and reservoir objectives while at the same time reducing workover costs. After implementation of each new technology, an evaluation based on both mechanical and reservoir factors was performed. Mechanical success was defined as the completion of the required scope of work with appropriate testing successfully completed. Reservoir success was defined by long and short term reservoir performance compared against pre-job expectations. This paper concentrates on the mechanical aspects of each technology, however reservoir performance has also been discussed where appropriate. Each of the new technologies trialed are discussed in the following sections; Scab Liners with Inflatable Packers A number of horizontal wells in Bass Strait were identified as potentially producing either gas or water preferentially from the heel of the horizontal section. The cost of traditionally used methods for water or gas shut-off such as tubing pull re-completions for installation of mechanical isolation equipment or cement squeezes made them uneconomic.

SPE Member Abstract Precise documentation is a key element in the management and control of critical equipment. Having correct and easily accessible information for equipment which in some cases is in excess of 20 years old has saved Esso Australia Ltd thousands of dollars in engineering time and has reduced rig downtime. Safety and the Environment are of prime importance in Esso operations and the management of critical equipment is instrumental in achieving objectives for these areas. Esso has completed an extensive program to document and control critical wellhead equipment and this has involved:–Surveying and documenting the 300 existing wellheads offshore;–Increased emphasis on material specification and control;–Reviewing and implementing new technology;–Increased control over wellhead equipment refurbishment; and–Increased emphasis on offshore wellhead maintenance. Benefits experienced by Esso after increasing the focus on critical equipment management include increased safety, increased confidence in equipment, decreased engineering time, and decreased rig downtime related to incorrect or incomplete information. Introduction The Esso / BHP Petroleum joint venture currently has 14 production platforms (with another two under construction), two sub-sea completions and two single well mono-towers in Bass Strait. These facilities, operated by Esso, include 300 wells which produce oil and gas from the Gippsland Basin (Figure 1). In the context of this paper, the designation 'critical' is used to differentiate that which is vital to the prevention of a major event such as an uncontrolled emission, fire or explosion that poses serious danger to people, property or the environment. Wellhead equipment is therefore critical and this paper will discuss the following topics related to its management:–Documentation;–Material specification;–Equipment specification;–New technology and its implementation;–Refurbishment; and–Maintenance. P. 281^

While DAS VSP has become relatively standard in dry-tree applications, acquiring data in subsea wells has remained a technical challenge as umbilical can be tens of kilometers long, thereby reducing the overall quantity of backscattered light to the topside interrogator. This adds to the attenuation due to connectors at the wellhead and along the optical path. Yet, the need for subsea DAS interrogation is high, particularly with the onset of complex, deep-water projects that will require on-demand monitoring capabilities. In this article, we report on the successful acquisition and subsequent processing of a zero-offset VSP in an ultra-long step-out context. We simulated a subsea well with 69km worth of lead-in fiber to the wellhead, including attenuation at the wellhead mimicking the connectors. The attenuation was tackled by using an active, subsea amplifier (that would normally sit at the wellhead), and an in-house developed engineered fiber that provides a significant uplift in backscattered energy. We acquired this ZVSP both on fiber and with a standard wireline tool string for comparison. The approach presented here combines hardware and processing strategies to tackle the long step-out challenge. We demonstrate the ability to record seismic data even at very large step-out, a requirement for subsea well monitoring.

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