This document summarizes gas hydrate problems faced by Petroleum Development Oman in their oil production operations and their integrated inhibition program to address it. Specifically: 1) Gas hydrates were forming in gas lift lines during Oman's coldest winter months, causing wells to cease production. Methanol was used as a hydrate inhibitor but posed health, safety and environmental issues. 2) The project aimed to find alternative, safer hydrate inhibitors and develop an early warning system to detect hydrate formation before pipeline blockages. 3) Laboratory tests showed that combining a kinetic hydrate inhibitor with 20% monoethylene glycol (MEG) achieved over 40 hours of hydrate protection at low inhibitor doses and was

1. IPTC 13061 Gas Hydrate Problems in Desert of Sultanate of Oman: Experiences and Integrated Inhibition Program Ardian Nengkoda, Abdulla Harthy, Wael Afify Taha, Hendrikus Reerink, Petroleum Development Oman, Alfred Hase, Champion Technology, Lamda Muchjin, Crescent Petroleum, Supranto, Suryo Purwono, Gadjah Mada University Phone: +968-24670501, Fax: +968-24670632, E-mail: ardian.nengkoda@pdo.co.om Abstract Currently, there are more than 10 oil producing station, in both North and South area operation of Petroleum Development Oman, which facing a unique gas hydrate problems. Most of these wells are producing by the support of gas lift. Therefore, it is very important that the gas lift network is kept optimally operating to maintain the intended production. The ambient temperature in Sultanate of Oman desert drops to as low as 5°C during the coldest 3 months in winter, when hydrates form in several gas lift lines. This causes affected wells to cease production and results in unscheduled deferment. So far, the problem was partly controlled by the use of methanol as hydrate inhibitor (a proven method used worldwide to restrict gas hydrate formation), however there are resulted many issues mainly HSE associated with the use of methanol. The main objectives of this project are to look the other chemicals alternative as hydrate inhibitor – move from methanol to another cost effective and safe chemical inhibitor and the goal is to ensure that the system is adequately inhibited against hydrate formation and that inhibitor injection is optimized. The second goal is to develop a warning system should hydrate start to form (prior to hydrate build up and pipeline blockage). The paper also defines laboratory testing as mandatory requirement to test an alternative hydrate inhibitor and practical facilities up grade. 7-9 December 2009, Doha, Qatar X-58 X-48 X-9 X-14 Moderate hydrate (1 or 2 times g/l flow stop – white line) Worse hydrate (erratic flow of g/l-white color) Before and after heat tracing installation Chemical Injection Current Operation Hydrate Envelope without Methanol and With Methanol Injection Three Cavities in Gas Hydrates Schematic of a hydrate autoclave

2. Conclusions and Project Plans The results of the autoclave tests are presented in Figures 8 and 9, and are summarised below. Dose rates of the kinetic hydrate inhibitor and thermodynamic inhibitor are based on produced water volume scenario. For gas compositions X Field as Table 2, two blank tests were performed each using DI water only (no KHI, Corrosion Inhibitor or a thermodynamic inhibitor). The induction time tH (which is the duration from start until the point where hydrates starts to form indicated by a pressure drop) was recorded as being approximately 2 hours. First tests have been performed with KHI on its own to check which KHI is showing the best performance for this application. Relatively fast it was noticed that even at higher KHI dose rates the obtained induction times were relatively short, less than 12hours. Therefore it has been decided to add MEG as a thermodynamic inhibitor to reduce the sub cooling further into a region, where the KHI can protect the system longer against hydrate formation. The dose rate for the kinetic hydrate inhibitor and the thermodynamic inhibitor MEG are based on produced water. Results obtained with 15% and 17.5% MEG (vol.%) showed no improvement in the performance of the KHI at 3.0%. The threshold level was obviously achieved when 20% MEG was added to test runs. At that MEG concentration the induction times was increased to over 40 hours at a constant dose rate of 30000ppm KHI. With 20vol.% (22.2wt.%) MEG the hydrate equilibrium temperature was dropped to 15°C at 58bar, which leads to a sub cooling of ~10°C. Due to the fact that the sub cooling has been lowered by the injection of 20% MEG, further tests have been performance in order to check whether it is possible to achieve a further reduction in the KHI dose rate. Autoclave tests at 22500ppm didn’t improve the KHI performance, but at 25000ppm the determined induction time was 59 and greater than 72hours (test was stopped) respectively. Based on these results the optimal performance of the KHI has been achieved in lab tests at 2.5% dose rate in the presence of 20% MEG and 20ppm Corrosion Inhibitor as Figure 9. For a shorter protection time against hydrate formation less KHI might be required. A programme of laboratory tests under PDO X Fied conditions showed that: - The addition of MEG is required in order to achieve a reasonable performance of the KHI - The additional amount of MEG was 20% for the X Field gas, the percentages are based on produced water at gas lift line. - No significant impact of the Corrosion Inhibitor has been observed during the lab test and further field testing will be conducted to reflect laboratory testing - Hydrate formation is a very expensive problem faced by the oil and gas industry, which must be solved in an economically and environmentally appropriate manner. IPTC 13061 7-9 December 2009, Doha, Qatar Before increase injection rate after increase injection rate Increasing flow rate of gas lift through the well give slight effect to duration of hydrate formation at control valve (light blue line) Fig. 8 Blank Test Result Fig. 9 Result KHI Optimization