Petroleum Geoscience - Volume 18, Issue 3, 2012

New exploration opportunities and improved imaging of already known prospects in the Caspian Sea, Kazakhstan, are presented, based on the acquisition, processing and interpretation of long-offset 2D seismic data acquired by CGGVeritas from 2006–2009. We have identified further examples of three already successful plays in the Caspian Sea and onshore, within open blocks in the North Caspian and North Ustyurt basins and a fourth, relatively unknown play, in the North Ustyurt basin. The already known plays include Devono-Carboniferous carbonate reefs and clastics, Triassic–Tertiary post-salt clastics and carbonates in the North Caspian basin and Jurassic–Cretaceous post-thrust clastics and carbonates in the North Ustyurt basin. The fourth play that we have identified comprises thrust faults, anticlinal structures with Late Palaeozoic–Early Mesozoic clastic and carbonate reservoirs in the North Ustyurt basin which, to our knowledge, has not been tested elsewhere in the region.

In western Kazakhstan there are several world class hydrocarbon fields, including the onshore Karachaganak Field. The geological setting is very challenging for the seismic imaging techniques where deep carbonate platform targets underlie a complex overburden including diapiric and detached salt structures. Furthermore, the extensive oil field infrastructure generates a noisy environment for seismic acquisition and reduced access for vibroseis trucks.

KPO conducted an extensive integrated feasibility study for a new survey, complemented by a seismic acquisition test in 2008 which confirmed the need for dense source and receiver coverage, long offsets and wide azimuths to optimize imaging of the pre-salt targets. The survey was acquired in 2009 and survey execution exceeded local and international standards. It was the highest channel survey acquired in Kazakhstan and when fully depth image processed it will yield a high spatially sampled seismic volume, with improved resolution and structural definition. The application of the latest technology and techniques will enable better characterization of this complex carbonate reservoir, adding future value by better placement of wells and reducing overall costs for the ongoing development of the field.

The Karachaganak Field is an oil and gas condensate supergiant field located in the western Kazakhstan Pricaspian Basin. As part of the challenge to improve reservoir knowledge, KPO has been continuously monitoring the reservoir using a microseismic array deployed downhole since February 2009. Continuous deep recording of microseismic activity is an innovative technique for reservoir monitoring; progressive refinements were made to fine-tune the acquisition and processing techniques. By December 2010, 8074 events had been detected and, from this group, 2556 events have been located. Events within the reservoir were recorded up to 8 km from the array to a depth of 5 km with moment magnitudes (Mw) ranging from −2.4 to +1. Microseismic events are continuously located and their spatial and temporal distribution analysed. This basic analysis is the input to an integrated study that considers the static model for the reservoir, in addition to dynamic and operational aspects such as production and injection rates, pressure baffles, drilling behaviour and casing perforations. The results to date indicate valuable reservoir information concerning the location of lateral and vertical reservoir pressure baffles and delineation of zones of instability at the reservoir–seal interface, important for well integrity issues. This new information is helping to improve dynamic and geomechanical reservoir models and also wellbore stability predictions.

This article presents the details of the Karachaganak microseismic array and how microseismic events were located. Discussion follows on the interpretation and the possible impact on reservoir monitoring and drilling. The Karachaganak array is one of the deepest installations of a passive microseismic monitoring system and also represents one of the longer periods of continuous monitoring, with two years of data available.

This study focuses on the reservoir characteristics of a Permian tight gas field in the Southern Permian Basin, Eastern Frisia, Germany. To improve the understanding of the reservoir, 3D seismic, wireline and core data were compared with a reservoir analogue in the Panamint Valley, United States. Depositional environments of the Permian Upper Rotliegend II include perennial saline lakes, coastal parallel sand belts comprising wet, damp and dry sand flats and aeolian dunes with interdune deposits. Polygonal patterns at different scales were observed on seismic horizon slices in the reservoir intervals and the overlying Zechstein. Outlines of superordinate polygons coincide with interpreted faults. Similar polygonal networks were identified on modern dry lakes in the western United States. The kilometre-long, up to 1.20 m deep open fissures in the Panamint Valley are interpreted to originate from the combined effects of synaeresis and tectonics. Subsequently, the fissures were filled with aeolian sediment. Vegetation growth confined to the lineaments indicates enhanced fluid circulation. Such fissures systems may serve as weakness zones and fault grain and impact reservoir quality in terms of hydraulic connectivity of reservoir compartments. For the Rotliegend reservoirs, original porosities and permeabilities of these zones were reduced to a minimum by enhanced cementation along the fluid migration pathways. Permeability barriers and reservoir compartmentalization, which can be clearly depicted on seismic attribute volumes, are a potential result of this development.

Reservoir compartmentalization can seriously compromise a project’s economics if left undetected during appraisal. Its early identification is made more likely if maximum use is made of available fluid appraisal data. This involves making a critical comparison of time-scales for various fluid properties to equilibrate compared with the actual time since those properties were initially disturbed. Spatially varying fluid properties indicate compartmentalization if they have existed for longer than the time needed for them to equilibrate.

Here we use data from appraisal wells and reservoir mixing time-scales to investigate vertical and horizontal compartmentalization in the Horn Mountain Field (Gulf of Mexico) and to quantify the properties of the baffles/barriers identified. We compare our results with earlier work using time-lapse geochemistry and mud gas isotope logging. Present fluid compositional variations in the field are shown not to be diagnostic of horizontal compartmentalization as the mixing time-scales by molecular diffusion are longer than the time since the reservoir filled. In contrast, pressure shifts and density differences are diagnostic. They indicate that faults within the Horn Mountain Field are relatively impermeable and would act as barriers during oil production. They also confirm that a shale-filled channel acts as a barrier to vertical flow.

We review the structural genesis and evolutionary history of basins along the Brazilian South Atlantic margin from the Sergipe-Alagoas (north) to the Pelotas basin (south), and demonstrate the links with petroleum system and play development. In our approach, we first break basins down into their tectonostratigraphic megasequences and define their characteristics, particularly focused on the development of characteristic source- and reservoir-rock intervals. We then compare these megasequences with similar types of megasequences in other basins, thereby providing a means to learn through a greater population of analogues. We demonstrate, using trajectory plots, that these basins experienced a similar tectonostratigraphic basin evolution, resulting in the deposition of many analogue potential source- and reservoir-rock intervals. These give rise to the development of similar types of potential petroleum systems and play (level)s. Although the area is currently being actively explored, large areas remain poorly understood, with unknown source-rock maturity distributions and many unknown/untested reservoirs/plays. This approach allows us to make analogue comparisons between the Brazilian marginal basins in order to evaluate and predict the presence of potential, yet undiscovered or under-explored, hydrocarbon accumulations.

This paper presents an integrated seismic, petrophysical and core facies study of the Mey Sandstone Member of the Central North Sea Lista Formation. Seismic mapping and attribute analysis reveal that the Mey Sandstone Member is composed of distinct axial and lateral routing systems. In turn, the axial system can be divided into coeval western and eastern fairways defined by the underlying graben topography in a similar manner to the overlying Sele Formation (Forties) sandstones. These trends are confirmed by petrophysical analysis, which also reveals that the lateral systems are not as important as previously proposed and that the cycles of the Mey Sandstone Member prograded over time before a late stage of backstepping. These variations can be related directly to published sea-level curves. Core analysis reveals that mean grain size is the main control on sandstone quality and that similar proximal (channelized) to distal (sheet-like) changes in sedimentological facies occur to those described in the Sele Formation. It is argued that these deposits cannot be described as simple basin floor fans due to the impact of topography on turbidite flow routing and the existence of multiple entry points of sediment into the basin.

Cenozoic carbonate platforms in the central Mediterranean region show distinct vertical changes in carbonate skeletal assemblages and porosity characteristics that reflect shifts in environmental conditions affecting the western Tethys. The Photozoan Association produced by carbonate ecosystems adapted to low nutrient environments and the Heterozoan Association favoured by mesotrophic conditions alternate through time over the Malta Platform and nearby carbonate platforms, although not in phase with trans-Mediterranean Oligocene carbonates. This anomaly reflects the transitional nature of Cenozoic climate as well as continental convergence of the Tethyan margins. Restricted conditions amplified the effect of nutrient flux from North African fluvial systems, which was controlled by meridional shifts in the inter-tropical convergence zone (ITCZ) precipitation belt. We model the climate–carbonate interaction by comparing the global oxygen isotope proxy to ice volume and meridional position of the ITCZ to changes in trophic level of carbonate ecosystems. The results show that the development of Palaeogene Mediterranean photozoan assemblages coincides with periods when the ITCZ had shifted away from North Africa (as is the case presently), whereas the heterozoan assemblages thrived during increased nutrient flux when the precipitation belt was located over the Sahara. The climatic controls resulted in facies characteristics that exert a fundamental influence on porosity in carbonate reservoirs.