Africa (Sub-Sahara) Bowleven began drilling operations at its Zingana exploration well on the Bomono permit in Cameroon. Located 20 km northwest of Douala, Cameroon's largest city, the well will target a Paleocene (Tertiary) aged, three-way dip closed fault block. The company plans to drill the well to a depth of 2000 m and will then spud a second well in Moambe, 2 km east of Zingana. Bowleven is the operator and holds 100% interest in the license. Asia Pacific China National Offshore Oil Company (CNOOC) has brought its Dongfang 1-1 gas field Phase I adjustment project on line ahead of schedule. The field is located in the Yinggehai basin of the Beibu Gulf in the South China Sea and has an average water depth of 70 m. The field is currently producing 53 MMcf/D of gas and is expected to reach its peak production of 54 MMcf/D before the end of the year.
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.
A pre-exploration well was drilled in the Xihu Sag of East China Sea basin, and commercial oil and gas flow had been achieved. But the oil and gas bearing trap had a big depth with low closure height and small area. The resolution of seismic data acquired by towed streamer is low, so it's difficult to obtain seismic velocity precisely. There were great risk and uncertainty in description of the trap and distribution of gas-bearing sandstone, reservoir prediction of sweet spot, direct hydrocarbon indication, and reserves assessment.
In consideration of the drilling platform on the trap, seismic acquisition technique of walkaway VSP and walk around VSP were introduced, meanwhile some innovative methods in source, receivers and geometry were applied. Twenty three-component hydrophones were composed as signal receivers which had a sample interval of ten meters in the well, two straight shot lines and two loop shot lines were designed around the drilling platform. Besides, volume and depth of air gun array were optimized, and the sailing route of seismic source vessel was planned properly in order to improve the efficiency of collecting work.
The collecting work of walkaway VSP and walk around VSP was accomplished efficiently, and more than seventy kilometers VSP seismic data was achieved. Afterwards, the new data was processed finely in company with zero offset VSP data, so high resolution VSP profiles and accurate seismic velocity were obtained. Reprocess to original seismic data acquired by towed streamer was implemented on the basis of walkaway VSP and walk around VSP data. The quality of normal seismic data was improved through reprocess constrained by walkaway VSP data, and S/N and resolution were much higher than old data. So it would be credible to research the distribution of gas-bearing sandstone and direct hydrocarbon indication using the reprocessed seismic data.
It was the first time to use joint acquisition technique of walkaway VSP and walk around VSP in offshore China which was an important breakthrough. High resolution VSP seismic profiles and precise seismic velocity could be acquired, and the data was important basis for refined evaluation of pre-exploration targets. It's very necessary to popularize and utilize these new techniques further.
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.
Yin, Qishuai (China University of Petroleum) | Yang, Jin (China University of Petroleum) | Zhou, Bo (CNPC Drilling Research Institute) | Luo, Ming (CNOOC China Ltd.) | LI, Wentuo (CNOOC China Ltd.) | Huang, Yi (CNOOC China Ltd.) | Sun, Ting (China University of Petroleum) | Hou, Xinxin (China University of Petroleum) | Wu, Xiaodong (China University of Petroleum) | Wang, Junxiang (China University of Petroleum)
The South China YQ Basin with 15 trillion cubic meters natural gas is typical of ultra high temperature-high pressure (ultra-HTHP) with the highest bottomhole temperature (BHT) at 249°C, the maximum bottomhole pressure (BHP) at 142MPa and the extremely narrow pressure window. Therefore, there are kinds of technical challenges during drilling there. In recent years, the managed pressure drilling (MPD) has been successfully applied in the basin with risks and well cost reduced instead.
The operational designs of MPD consist of three parts: the precise calculation of drilling fluid equivalent circulating density (ECD), the optimization of operational parameters and the well control. The first part includes four models: the wellbore temperature field model, the drilling fluid equivalent static density (ESD) model, the drilling fluid rheological property model and the effects of cuttings concentration on ECD. The second part is the determination of the two key operational parameters: the mud weight (MW) and the surface backpressure (SBP). The third part is the plans of three cases: downhole accidents, equipment failures and termination conditions of MPD.
The first part includes four steps: establish the instantaneous wellbore temperature model based on the convection and thermal conductivity theory by dividing the wellbore into five areas; establish the ESD model by considering the elastic compression effect of HP and thermal expansion effect of HT; establish the drilling fluid rheological property model based on the Herschel-Buckley model by considering the effect of ultra-HTHP on dynamic shear force, consistency coefficient and liquidity index; consider the effects of cuttings concentration on ECD based on the solid-liquid two-phase flow. The ECD model is established based on above models. The second part includes two steps: determine the MW based on the critical pressure constraint principle by the operational window simulation of different well depth and fluid volume; determine the SBP of pump-on and pump-off by considering the rated operating pressure of the equipment, the calculated pressure loss and the 0~1MPa higher BHP than formation pressure. The third part includes three steps: make the emergency measures against downhole accidents by well control matrix; make the emergency measures against the failure of equipment such as rotating control device (RCD); determine the MPD termination conditions such as drilling big cracks.
The MPD is successfully applied to X gas field featuring offshore ultra-HTHP. The casing structure is optimized from 7-8 layers to 5 layers and the well is drilled in the micro pressure window of 0.01~0.02sg without accidents. Additionally, the non-productive time (NPT) decreases by 60% and the well cost is obviously reduced. Generally, the MPD yields time and cost savings for tomorrow's market.
The existence of anisotropy and viscosity in real stratum has quite influence on seismic waveform and amplitude value. Without considering that, final migration result may suffer from low resolution and even wrong imaging position. To get better reservoir description in complex area, the application of generalized standard linear solid theory is extended from isotropic media to anisotropic media. By introducing the regularization operator to eliminate high-frequency instability problem, robust and applicable inverse wave-field continuation is achieved. Based on the combination of pseudo-spectral method and finite difference method, efficient visco-acoustic VTI RTM gets realized and shows improved imaging quality on synthetic data.
In practical seismic exploration, usually ideal acoustic and isotropic media are assumed for imaging process. However, as a matter of fact anisotropy widely spreads in real earth media. Ignoring this causes low imaging quality, displacement from actual position and so on (Duveneck E, Bakker P, 2011). Another effect is viscosity which behaves as energy absorption and phase distortion during wave propagation. For example, fluids trapped in geologic structures cause strong amplitude attenuation (Zhang, J, Wu J, Li X, 2013; Zhu T Z, Harris J M, Biondi B, 2014). The imaging resolution in deeper area degrades due to high frequency attenuation. Current research mainly focuses on one aspect, that is, either anisotropy or viscosity. Therefore, imaging can be further improved if taking both of them into account.
Of course it would be a better way to handle anisotropy and viscosity in elastic wave equation which describes the actual seismic wave propagation in real earth media accurately. However, even conventional elastic RTM requires much more computation expense and memory occupation, not to mention considering complex case. In addition, we mainly get P component recorded in data acquisition (Jiubing Cheng and Wei Kang, 2013). Consequently acoustic approximation applies to process this kind of seismic data. Another advantage would be that viscous anisotropic wave equation would be significantly simplified in acoustic case which made it applicable in practical use.
Liu, Bo (Schlumberger China Petroleum Inst.) | Lu, Qing Zhi (Schlumberger China Petroleum Inst.) | Kuznetsov, Vladimir (Schlumberger China Petroleum Inst.) | Cai, Huimin (Schlumberger China Petroleum Inst.) | Yang, Hongjun (CNOOC Zhanjiang Ltd.) | Guo, Shusheng (CNOOC Zhanjiang Ltd.) | Gao, Yongde (CNOOC Zhanjiang Ltd.)
Deepwater sedimentary systems have been widely investigated for more than half a century. Geoscientists define many types of facies, elements, and/or processes separately. The continuum of processes ranging from debris flow, to turbidity flow, and to bottom-current flow indicates a continuum of facies that result from the process or process overlap. However, these essentials are always overlooked to classify deepwater processes and their definitive facies. Most deepwater reservoirs, irrespective of the process, have been uniformly called turbidites for quite a long time. The incomplete understanding on the facies-process increases drilling capital and risk because different “turbidites” have variable petrophysical properties.
In the case study of the Yinggehai basin offshore south China, the main deposits are from a deepwater submarine fan system. Previous researchers inadequately defined facies as channel, lobe, levee overbank, and sheet sand without sedimentary processes. To better understand the petrophysical property variation of different facies, we integrated borehole image, seismic, core, and nuclear magnetic resonance (NMR) logs to unravel and redefine the facies-process based channels and lobes. The fit-for-purpose approach identified downslope process, alongslope process, and overlap process of downslope and alongslope; therefore, we proposed six types of facies-process based channels and four lobes. The channels include turbidity channel, sandy, muddy, and granular debris channel (downslope), internal waves-tides channel (alongslope), and internal waves-tides reworked channel (overlap). The lobes are sandy debris and turbidity lobe (downslope), internal waves-tides lobe (alongslope), and internal wave-tides reworked lobe (overlap). Among all of the facies, the internal waves-tides (affected) channel and lobe are the best reservoirs because the dispersed clay is winnowed and the sands were reworked by bottom current internal waves-tides; the turbidity channel and lobe are the second best reservoirs, followed by the sandy debris channel and lobe.
The unraveling of facies-process based deepwater sedimentary systems fills the gap in understanding deepwater sedimentary systems with variable petrophysical properties and reduces the future field development uncertainties.
Key words: facies-process, Yinggehai basin offshore South China, downslope, alongslope, internal waves-tides, borehole image, NMR logs, sandy debris flow, channel, lobe.
Overview of Sediment Gravity Flow, Processes, and Facies
Dott (1963) was the first to classify gravity flows based on fluid rheology. Later, Middleton and Hampton (1973) proposed to define sediment gravity flows as flows consisting of sediment moving downslope under the action of gravity. They distinguished four main types of such flows: (1) turbidity current, in which the sediment is supported mainly by the upward component of fluid turbulence, (2) fluidized sediment flows, in which the sediment is supported by the upward flow of fluid escaping from between the grains as the grains are settled out by gravity, (3) grain flows, in which the sediment is supported by direct grain-to-grain interactions (collisions or close approaches), and (4) debris flows, in which the larger grains are supported by a “matrix”; i.e., by a mixture of interstitial fluid and fine sediment, which has a finite yield strength (Fig. 1). Sanders (1963) established the foundation of process sedimentology by interpreting fluid mechanics from sedimentary structures. Process is a mechanism of sediment erosion, transport, and deposition. Facies is a distinct sediment type, a description of lithology (color, grain size, compositional and textural maturity), and sedimentary structure and texture (laminated, graded, massive et al); therefore, processes are the conclusions from the facies.
Wang, Zhifa (China University of Petroleum and Sinopec Research Institute of Petroleum Engineering) | Jiang, Guancheng (China University of Petroleum) | Lin, Yongxue (Sinopec Research Institute of Petroleum Engineering)
When the bottom hole temperature (BHT) is over 356°F, polymers and sulfonated agents of fresh water based drilling fluid generally degrade or loss effect quickly. To address this problem, we developed a low cost formulation including extra high temperature (430°F) polymers with sulfonated agents for BHT under 390°F with 87.5 pcf mud weight. This drilling fluid formulation was lab tested to have the mud properties of PV 40 mPa.s, YP 12 Pa, HTHP (390°Fand 500psi) FL 12ml and lubricant factor 0.05. The mud formulation was field tested from 14,890 to 20,036 ft of SINOPEC XW-3 Well in Guangdong, China. The measured maximum static BHT was 410°Fwith actual minimum 69pcf mud weight used. The drilling operation was successfully conducted without a major problem in this well with this new designed drilling fluid even though loss was encountered in this section of well that forced the lowering of mud weight to 69 pcf. At the same time, we believe the formulation can be used similar condition when the BHT is between 356°Fand 390°Fwithin desired mud weight of 87.5pcf. The formula also can adjust and use high salinity ultra-deep HTHP well.
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.