Fines migration is widespread in oil and gas reservoirs but often misunderstood. It can be difficult to identify and even more difficult to predict and interpret. The phenomenon, which can be considered a "natural" damage mechanism, involves the movement of rock particles through and within the pore matrix of that rock. This paper presents a case history of fines migration investigation in a reservoir in the Malay basin in South East Asia. High temperature core flood tests and equivalent ambient condition core flood tests were used to evaluate the potential for fines movement in the producing gas phase. This paper outlines the laboratory test procedures, the results and discusses the implications. A comparison is made between the different laboratory techniques and recommendations made for similar reservoir challenges. The importance of scaling down near wellbore flow rates from field conditions to make them relevant in laboratory conditions was considered. Thus the test results are now able to be scaled up and are more relevant. This paper will also show significant differences in permeability reduction and fines movement between ambient conditions and high temperature reservoir conditions. The testing at high temperature reservoir conditions has not been a common practice and no published work has been found within SPE on this topic. Once fines movement is predicted, the next challenge is to evaluate its potential impact on well performance. The implications for the specific reservoir and particularly for well design and completion options are discussed. Sand control issues as well as the potential impact on water injection or disposal wells are considered. This paper presents clear evidence for fines migration in the production phase of a high temperature gas reservoir. Laboratory testing and subsequent analysis of tested samples demonstrate the nature of the fines and the process of permeability change. A process for identification of potential fines migration problems in gas reservoirs is proposed. The implications of fines migration in such a reservoir are discussed and potential mitigation is considered together with well completion design implications. Introduction Block A-18 is located within the Malaysia-Thailand Joint Development Area (MTJDA), offshore South China Sea in water depths ranging from 150 to 200 feet. The block is currently operated by Carigali Hess on behalf of a Production Sharing Contract (PSC), contractors Petronas Carigali (JDA) Sdn. Bhd., Hess Oil Company of Thailand and Hess Oil Company (JDA) Ltd. In 1990 the governments of Malaysia and Thailand signed the Malaysia Thailand Joint Development Area (MTJDA) agreement and established the Malaysia Thailand Joint Authority (MTJA) Act. In 1994, the MTJA awarded the PSC for Block A-18. In Block A-18 several gas holding areas are currently being operated. They are the Bumi, Suriya, Cakerawala, and Bulan fields. In all four fields the reservoir sequences are grouped into three different intervals, Shallow, Intermediate, and Deep. Currently only the Shallow and Intermediate sequences are being developed. For several years Carigali Hess has been attempting to evaluate and test the Deep intervals in the Bumi Field. In October of 2007 a successful drill stem test was conducted on Bumi-9 in the Deep intervals and the planning of a pilot project to install two completions into the Deep intervals commenced. The planning for these Deep sequences is quite extensive as they are HPHT intervals, with high CO2, traces of H2S, and the gas could contain traces of mercury. The temperatures are approximately 400 °F (205 °C) and the pressures bordering 10,000 psi with over a 0.8 psi/ft pressure gradient throughout the Deep intervals.

A case history from Offshore Israel is presented that describes the successful delivery of one (1) ultra-high rate gas well (+250 MMscf/D) completed in a significant (11.5 TCF) gas field with 7 in. production tubing and an Open Hole Gravel Pack (OHGP). The well described, Tamar 8, was completed approximately 4 years after the start of initial production from the Tamar development. Several operational innovations and process improvements were implemented that resulted in a significant reduction in rig time. A novel multi-purpose integrated tool string design enabled the sequential drilling of the pilot hole, underreaming of the reservoir section, several fluid displacements and casing cleaning in a single trip. The completions were installed with minimal operational issues (completion Non-Productive Time, NPT = 2.6%). Production commenced in April 2017. The initial completion productivity of this new well exceeded the five wells completed in 2012. Peak production rate to date is 281 MMscf/D.