Turbidite reservoirs of the Sele Formation, Central North Sea: geological challenges for improving production
Turbidite reservoirs of the Sele Formation, Central North Sea: geological challenges for improving production
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北海中部 Sele 组浊积岩储层：提高产量的地质挑战
DOI：
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发表时间：
2005
期刊：
影响因子：
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通讯作者：
C. Harvey
中科院分区：
文献类型：
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作者：
M. Hempton;J. Marshall;S. Sadler;N. Hogg;R. Charles;C. Harvey
北海中部Sele组的浊流储层产自Forties、纳尔逊、Montrose-Arbroath、Scoter、Pierce、Gannet丛、Guillemot A、Mirren等油田，目前正在对Merganser、Phyllis、Starling和Blane等油田进行评价/开发。这些水库形成了“四十年代”海底扇系统的一部分，该系统来自西北部和西部的补给水道。与威尔斯井相关的毯式三维地震覆盖显示，在靠近上倾源的地方，浊积岩较厚，净：毛比较高，且更通道化。下倾，浊积岩储集层厚度较薄，粒度较细，沉积结构以叠加的瓣体和受可容纳空间和盐运动控制的小河道为特征。在上倾油田，如纳尔逊和福蒂斯，生产是成熟的。优质储层河道砂大部分被排干。通过应用注水和四维地震技术，可实现60-62%的采收率。这些储层中的剩余挑战是（1）在河道相中找到旁通油，以及（2）识别/模拟非河道化相（例如河道边缘和河道间相）中剩余的油。由于水上升和突破不均匀或页岩屏障，部分渠化储层未被波及。非沟道化储层未被波及，因为其砂层较薄，与页岩互层，储层质量较低。现有威尔斯井之间的剩余油区是不可分割的，强调了远离井筒的横向非均质性的不确定性以及静态储层建模技术对正确建模、识别和规划具有多重实现的加密目标的重要性。通过更高分辨率的地震解释和储层模型、应用提高石油采收率和神枪手钻井技术以及改进水管理，可以实现更高的采收率（可能高达70%）。在诸如Scoter、Merganser、Pierce和Guillemot A等下倾油田，生产并不成熟，威尔斯也不丰富。因此，开发规划更依赖于高质量的静态和动态储层模型来预测井间储层特征、体积和动态。一般来说，浊积岩储层砂岩较薄，粒度较细。最厚的砂可能更容易被风化成瓣状/席状。渗透率低于等效孔隙度的上倾储层（数十mD，而不是数百或数千mD），可能是由于平均粒度和结构成熟度的降低以及碎屑粘土基质的相应增加。最大的挑战在于模拟净横向变化：总厚度、层厚、相（特别是页岩层结构）和胶结作用。盐底辟、滑塌和滑坡的生长使沉积斜坡变得过于陡峭，从而导致储层剖面的横向不均匀性，降低了储层剖面的可预测性。多条断层从盐底辟中辐射出来，可能分隔储层。这些影响可以通过建立储层聚集和结构的可靠概念模型来减轻，并得到相关油田类比和详细生物地层学的支持，这些生物地层学可以描绘多个广泛的标志层。对于液态烃，采收率通常为40- 45%。天然气采收率预计为60- 65%。
Turbidite reservoirs of the Sele Formation in the Central North Sea produce from fields such as Forties, Nelson, Montrose–Arbroath, Scoter, Pierce, the Gannet cluster, Guillemot A, Mirren and are under appraisal/development in fields such as Merganser, Phyllis, Starling and Blane. These reservoirs form part of the ‘Forties’ submarine fan system that was sourced from feeder channels in the northwest and west. Blanket 3D seismic coverage tied to wells shows that nearer their updip sources the turbidites are thicker, higher in net:gross, and more channelized. Downdip, the turbidite reservoirs are thinner bedded, finer grained and with depositional architectures that are characterized by stacked lobes and minor channels controlled by accommodation space and salt movement. In updip fields, such as Nelson and Forties, production is mature. High-quality reservoir channel sands are mostly drained. Recovery factors of 60–62% are achievable by application of water injection and 4D seismic technologies. The remaining challenge in these reservoirs is to (1) find by-passed oil in the channel facies and (2) to identify/model oil remaining in non-channelized facies, such as channel margin and interchannel facies. Portions of the channelized reservoirs have not been swept because of non-uniform water ascent and breakthrough or shale barriers. Non-channelized reservoirs have not been swept because their sands are thin bedded, interbedded with shales and of lower reservoir quality. Remaining oil zones are not correlatable between existing wells, emphasizing the uncertainties of lateral heterogeneities away from the wellbore and the importance of static reservoir modelling techniques to properly model, identify and plan infill targets with multiple realizations. Higher recovery factors (possibly as high as 70%) may be achievable with higher resolution seismic interpretations and reservoir models, application of enhanced oil recovery and sharpshooter drilling techniques and improved water management. In downdip fields, such as Scoter, Merganser, Pierce and Guillemot A, production is not as mature and wells are not as abundant. Consequently, development planning is more dependent on high-quality static and dynamic reservoir models to predict the interwell reservoir character, volumetrics and performance. In general, turbidite reservoir sandstones are thinner and finer grained. The thickest sands may be more correlatable as lobes/sheets. Permeability is lower than in updip reservoirs of equivalent porosity (tens of mD as opposed to hundreds or thousands of mD), probably due to reductions in mean grain size and textural maturity and a corresponding increase in detrital clay matrix. The greatest challenges lie in modelling lateral changes in net:gross, bed thickness, facies (especially shale bed architecture) and cementation. Where depositional slopes were oversteepened by the growth of salt diapirs, slumps and slides introduce lateral heterogeneities and reduce predictability in the reservoir section. Multiple faults radiate from such salt diapirs and may compartmentalize the reservoir. These effects may be mitigated by the construction of robust conceptual models of reservoir accumulation and architecture, supported by relevant field analogues and detailed biostratigraphy which may delineate multiple widespread marker horizons. For liquid hydrocarbons, recovery factors are typically 40–45%. Gas recovery factors are projected to be 60–65%.