Using oilfield analogs to fuel E&P success

Figure 1 – Jubilee field in Ghana vs. other potential analogs.

A significant challenge facing E&P professionals is how to pool their experiences and also to filter the feast of opportunities. From exploration acreage to prospect, to field development and then finally asset acquisition or sale.

Where to start

Analysis of all the available data types – seismic, well logs, test and production data, cores and analogous reservoirs (oilfield analogs) aids technical and business decision making throughout the exploration and production supply chain. However, a lack of resources or time often overlooks analogs. In turn it also impedes due diligence. As a result, dry holes are drilled, field developments disappoint and the value of acquired reserves disappears to goodwill on the balance sheet. Whenever this happens it also naturally questions the quality of opportunity evaluation. A systematic way to reduce risks and better evaluate opportunities is therefore to benchmark them against oilfield analogs.

Using oilfield analogs to best effect

Comparing investment opportunities and successfully producing fields is easily possible. However, analogs are often applied with little rigour. Also a single analog is sometimes used just because it looks similar on seismic data or is conveniently located in the same basin or region.

The Jubilee field is well-known analog and also used for numerous exploration opportunities on the West African coast. However very few prospects are analogous with Jubilee’s setting. As a result some 59 dry or non-commercial wells were drilled at a cost of ~$4 billion. This immense wasted investment therefore highlights the risk in using a single analog to benchmark or characterise an opportunity.

The key to successful analog assessment is consistency across all technical parameters. From basin type, to tectonic regime, also structural setting, trapping mechanism, depositional system to the reservoir environment. Also from reservoir lithology to reservoir properties, thickness, seal lithology, configuration and more.

However, the development of a global oilfield knowledge base with a comprehensive yet consistently applied range of technical parameters requires huge time and cost. As a result it is beyond the capabilities of most E&P companies.

Figure 2 – C&C Reservoirs’ approach.

C&C Reservoirs' DAKS knowledge base and analytics tools

For over 20 years, C&C Reservoirs has invested in building a Digital Analogs Knowledge System (DAKS). This comprises a comprehensive knowledge base of the world’s most important oilfields as well as many clever analytics tools. Fields are characterised via 250 geological and 150 engineering parameters. Each parameter also forms part clearly defined classification system which has been honed over many years. As a result, this allows geoscientists and engineers to match data, and input and store technical static and dynamic data for their own prospects and plays. It also enables direct comparison against analogous fields.

Statistical analysis of an opportunity’s key technical data versus the analogs is generated as P10-P50-P90 percentile distributions. Thus benchmarking E&P opportunities against numerous global analogs enables better and more focused analysis of the potential risks. In turn it also makes sure decisions are based on facts rather than the experiences of a handful of people and/or just one oilfield analog.

Using global oilfield analogs

Some analog applications are discussed below:

Play characterisation
In a recent licensing round, new exploration blocks were offered in a growing oil producing region. However, well and seismic data was sparse. Therefore by searching and analysing parameters based on the tectonic setting of the blocks, a play characterisation was developed based on 60 similarly-aged producing reservoirs in similar tectonic settings. As a result, potential bidders could characterise their plays by selecting from up to 400 technical parameters. This therefore allowed early economic screening i.e to determine a MEFS (minimum economic field size). The characterisation also highlighted potential production problems including high viscosity oil and inert gas content. Both factors complicated potential field development and thus risked increasing project costs.

Prospect benchmarking

Benchmarking prospects against field analogs on a P10-P50-P90 distribution basis automatically highlights parameters lying outside of the first and last deciles. For example, when evaluating ‘Prospect X’, a Mesozoic lateral depositional pinch-out trap against 36 analogous fields, two parameters lay outside the normal P10-P50-P90 percentile distribution (see figures 3 and 4). Namely, the structural dip of the trap and the prognosed seal lithology. This therefore alerted the interpretation team to investigate and resolve the seal issue. It also questioned the likelihood of the prognosed hydrocarbon column breaching the shale/siltstone seal. Understanding both issues thus clarified the drilling risk.

Figures 3 & 4 – Evaluating the risks at Prospect X, a histogram of the lateral depositional traps indicates that 90% of these types of traps have less than four degrees of dip, while additional analysis flags the fact that mixed lithology seals do not work beyond three degrees of structural dip.

Post-mortem analysis or post drill audits 
Comparing pre-drill and also post-drill findings both against each other as well as global analogs reveals anomalous pre-drill predictions and also post-drill results.

Field development planning 
Many performance uncertainties arise in early development stages. Analog analysis also provides quantitative ‘envelopes’ to plan how to optimise production.

Improved hydrocarbon recovery 
Fields in secondary and tertiary recovery production stages and also sharing similar geological and engineering parameters are readily identifiable. This therefore enables reservoir engineers to compare a particular field’s production performance versus others. As a result, revealing methods to enhance production and improve field performance.

Mature and abandoned fields 
Entering data from mature or abandoned fields allows assessment of the effect of specific technologies, such as horizontal and multilateral drilling, under-balanced drilling and also gravity-assisted thermal recovery on production. Thus on likely return on investment. For example, an initial review of a Central Asian field redevelopment concluded that the shallow reservoir depth combined with the low temperature and also a large number of structural compartments were critical factors. However, benchmarking, revealed that the two most anomalous parameters were oil gravity and also viscosity.  Nevertheless investigation indicated that high recovery was possible from high viscosity reservoirs and also that cyclical steam injection combined with closer well spacing (see figures 5 to 8 below) were appropriate recovery methods. As a result, the evaluation team revised its original plan by decreasing the well spacing to under 500m. Also by using steam injection and drilling horizontally. Consequently, the new redevelopment plan added multi-millions of dollars to the opportunity value.

Figure 5 – Assessing API gravity and viscosity.
Fig 6 – Assessing API gravity and viscosity.
Figure 7 – Key field parameters. Figure 8 – Analogue field production: 18–22° API, 180 mPa at reservoir.

Portfolio Analysis
Entering static and dynamic data for all your producing fields allows managers to compare fields and spot under and over-performers. In turn this also reveals candidates for divestment or further investment.


In the complex subsurface world of exploration and production, there will always be surprises, both welcome and also unwelcome. Therefore prepare for surprises and reduce the risk of surprises. First do this by reviewing analogous oil reservoirs as part of pre-drilling or production processes. In addition, rather than rely on one oilfield analog, which risks misleading, save time and money by learning from all of the world’s most important fields.

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