Gao, Yongde (CNOOC Zhanjiang) | Chen, Ming (CNOOC Zhanjiang) | Du, Chao (CNOOC Zhanjiang) | Wang, Shiyue (CNOOC Zhanjiang) | Sun, Dianqiang (CNOOC Zhanjiang) | Liu, Peng (Schlumberger) | Chen, Yanyan (Schlumberger)
Drilling in Ledong field at Yinggehai basin of South China Sea faces challenges of high-temperature and high-pressure (HTHP). The high pore pressure and low fracture gradient results in a narrow mud weight window, especially when drilling close to overpressured reservoir. Well LD10-C was the first exploration well targeting at reservoirs in Meishan formation. Well LD10-A and LD10-B were offset wells in a distance of 15-20km drilled for reservoirs in Huangliu formation, which is above Meishan formation. During drilling, both wells encountered severe gas kick, mud loss and did not reach target.
In order to drill and complete well LD10-C safely, a real-time pressure monitoring solution was introduced with integration technique of logging while drilling (LWD) and look-ahead vertical seismic profile (VSP). It helped to monitor pore pressure and fracture gradient while drilling and predicted top of the overpressured reservoir. This enabled to keep the mud weight and equivalent circulation density (ECD) within a safe margin to avoid kick and mud loss, helped to set casing as close as possible to the top of reservoir. The reservoir section was drilled with a manageable mud weight window.
The main achievements of this task were: 1) accurately monitor and predicted pore pressure coefficient at reservoir. The predicted pore pressure coefficient was 2.25 SG versus 2.24 SG from actual measurement. 2) accurate prediction of reservoirs top. The predicted top depth of Sand C was 2m error with accuracy of 0.05%. The top depth of Sand D was 10m error with accuracy of 0.2%. 3) 12.25in section and 8.375in section was successfully drilled deeper with pressure monitoring. The 9 5/8in casing was set 491m deeper and 7in line was set 80m deeper than plan. As a result, well LD10-C was drilled and competed without any drilling complexities.
This was first application of LWD and VSP together for pressure monitoring while drilling in Yinggehai basin. The successful completion of well LD10-C confirmed that this integrated solution was an efficient technique to predict and reduce drilling risks, optimize mud weight and casing diagram, improve operational safety and save cost in HTHP offshore drilling.
Is Surfactant Environmentally Safe for Offshore Use and Discharge? The current presentation date and time shown is a TENTATIVE schedule. The final/confirm presentation schedule will be notified/available in February 2019. Designing Cement Jobs for Success - Get It Right the First Time! Connected Reservoir Regions Map Created From Time-Lapse Pressure Data Shows Similarity to Other Reservoir Quality Maps in a Heterogeneous Carbonate Reservoir. X. Du, Y. Jin, X. Wu, U. of Houston; Y. Liu, X. Wu, O. Awan, J. Roth, K.C. See, N. Tognini, Shell Intl.
By International Petroleum Technology Conference (IPTC) Monday, 25 March 0900-1600 hours Instructors: Olivier Dubrule and Lukas Mosser, Imperial College London Deep Learning (DL) is already bringing game-changing applications to the petroleum industry, and this is certainly the beginning of an enduring trend. Many petroleum engineers and geoscientists are interested to know more about DL but are not sure where to start. This one-day course aims to provide this introduction. The first half of the course presents the formalism of Logistic Regression, Neural Networks and Convolutional Neural Networks and some of their applications. Much of the standard terminology used in DL applications is also presented. In the afternoon, the online environment associated with DL is discussed, from Python libraries to software repositories, including useful websites and big datasets. The last part of the course is spent discussing the most promising subsurface applications of DL.
This paper was selected for presentation by an OTC program committee following review of information contained in an abstract submitted by the author(s). The material does not necessarily reflect any position of the Offshore Technology Conference, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Offshore Technology Conference is prohibited. The abstract must contain conspicuous acknowledgment of OTC copyright. Abstract Burial of submarine pipelines and cables is common practice in the North Sea where potentially damaging threats such as fishing gear interaction and dragged anchors are high, or where burial is required for flow assurance. Whilst the requirement to bury pipelines in Asia-Pacific has not had the same imperative as in the North Sea, there is now a growing requirement for pipelines to be trenched, particularly to increase mechanical protection and improve on-bottom stability. Trenching is considered to be one of the offshore activities that carry most commercial risk. It is therefore important to ensure that the correct tool is selected for the anticipated field conditions and to establish realistic performance criteria based on regional experience in the prevailing seabed soils. This paper compares the primary differences between seabed sediments of the North Sea to those that prevail in Asia-Pacific and discusses where differences in these conditions can affect the choice of burial equipment and tool performance when planning trenching in this region. Performance benchmarks for most trenching systems are based on experience and empirical relationships developed for seabed soils typically found in more northern latitudes. Consequently, the main body of burial performance data does not account for the carbonate rich seabed sediments for example that are prevalent in the Asia-Pacific region. Carbonate cemented soils and weak rocks pose a significant challenge to burial and trenching experience in these materials remains very limited. A trenching case study is presented which highlights the challenges of designing an appropriate protection and burial strategy for this region and provides indications of actual performance that can be expected in some of the carbonate sediments typically found in an Asia-Pacific location. It is hoped that this paper will go some way to address the gaps associated with performance predictions in carbonate sediments and will provide a reference point on which to plan trenching work in Asia-Pacific region.
CNOOC is operating in YingGehai Basin and QiongSouthEast Basin of South China Sea. Formation testing has been routinely used by this operator in field exploration to confirm hydrocarbon presence, define the hydrocarbon type as well as getting PVT samples. Due to the high cost of DST operation in the offshore environment, formation testing is considered as the main testing method to test the small to medium size sand bodies. And the result is accepted to claim reserve of hydrocarbon.
As the recent offshore exploration has focused more on deeper formation where the sand permeability is between low to ultra-low, the pressure pretest mobility is easily lower than 1md/cp. In some particular formation, the formation mobility is even lower than 0.1md/cp. For this type of permeability of sand, testing becomes very difficult and getting fluid sample to claim reserve becomes a huge challenge. If the formation tester fails to obtain the samples, very often the later DST operation would not achieve a success.
A new probe module of formation tester has been introduced to the industry early 2013 and it has been designed to perform formation testing in low permeability environment. Especially it could apply a much higher drawdown than previous technology to move the tight hydrocarbon.
In this paper, a few cases will be presented to demonstrate how this new probe work in Yinggehai and QiongSouthEast basins fluid sampling operation where we sampled successfully at formation with the mobility is less than 0.1md/cp. With this result, great amount of reserve can be claimed and this new probe has been considered as the unique solution of testing these formation as well as predicting the possible production capability. .
DF1-1 gas field in the west of the South China Sea is associated with high concentration of CO2). Many options have been assessed by the operator (CNOOC) in recent years in order to dispose the CO2 separated from the gas stream. In this study, geological storage of CO2 into offshore saline aquifers near the gas separation plant on the Hainan Island is considered, and a demonstration project is proposed and designed in terms of aquifer selection and assessment, CO2 transportation and injection, and project economics. Several aquifer structures around the gas field and near the Hainan Island were investigated and
assessed with respect to geological structure, reservoir and trap features, fluid properties, storage capacity and site location. A saline aquifer (namely LT13-1), 60 km offshore the Hainan Island, was chosen as the storage site. CO2 will be transported by a long-distance subsea pipeline at high pressure and injected into the aquifer via a subsea well-head and through a horizontal well. Reservoir simulation and injectivity analysis have been conducted to estimate the injection rate and pressure, and also to predict the movement of CO2 after injection. A scoping economic analysis of the project was also conducted and presented in
Deng, Huifeng (COOEC Shenzhen Subsea Technology CO., LTD.) | Song, Chunna (COOEC Shenzhen Subsea Technology CO., LTD.) | Miao, Chunsheng (COOEC Shenzhen Subsea Technology CO., LTD.) | Dai, Wanbao (COOEC Maintenance Company)