What’s new in exploration

Deepwater exploration and development has proven billions of barrels of oil worldwide, with the potential of billions more barrels from new discoveries. The three main areas containing these deepwater discoveries are Brazil, West Africa and the Gulf of Mexico (GOM). A recent Research Project to Secure Energy for America under taking, partially funded by the Department of Energy’s National Energy Technology Laboratory, examined the possibility of improving success rates during exploration and appraisal programs through increased well testing. The study was done by Nautilus Intl., with participation from Knowledge Reservoir, LLC; Expro International Group Ltd.; General Marine Contractors LLC; INTECSEA WorleyParsons Group; Louisiana State University; The University of Tulsa; Texas A&M University; GE Oil & Gas; Tidewater Marine; and Huisman.

With all exploration, the big fields are discovered first, followed by medium-sized and smaller fields. Deepwater exploration has followed this trend, mainly because of the advances in seismic technology, especially processing, and advances in drilling, subsea completions and flow assurance. The reliance on seismic interpretations, electric logs and modular formation dynamic testers (MDTs) has formed the basis for the appraisal of a deepwater discovery, along with appraisal drilling. However, many deepwater wells have not met production and reserve estimates. Because of these costly disappointments, operators are willing to commission only the larger fields (i.e., 200 MMboe or greater) for commercialization in deep water.

The fact is that most companies do not know the size of their deepwater discoveries and have done a poor job of estimating reserves (i.e., electric/wireline logs and MDT data only provide information in close proximity to the wellbore, and seismic data cannot define the heterogeneity of the reservoir). Without knowing the size and production potential of a discovery, hundreds of millions of barrels of potentially commercial reserves discovered in the GOM, and in other deepwater regions of the world, will not be produced, because risks are too high.

Many operators now recognize that the only way to properly assess reservoirs is by conducting short-term and long-term well testing. These tests integrate all the reservoir properties away from the wellbore, to give the permeability and net producing intervals (true kh value), location of reservoir boundaries, compartment volumes, reservoir energy, and initial reservoir pressure, etc. For deep water and ultra-deep water, early reservoir appraisal challenges include the high costs, operational and environmental risks, and the multi-disciplinary coordination associated with well testing operations.

In deepwater field development, operators must manage the subsea requirements for well control, subsea equipment operations, and getting the flow from the well via some riser system—connected to a wellhead or subsea tree—to some type of processing vessel. Operators, knowing the complexity involved, have requested a more integrated look at early reservoir appraisal, utilizing well testing systems.

The study was divided into two parts: the first part was reservoir-oriented, and the second part focused on well test design and operations. The key points are given in an executive summary.

During the reservoir investigation phase, two major surprises occurred:

The common assumption has always been that high production rates were needed to test the three GOM types of reservoir plays (Middle Miocene, Lower Tertiary and Eocene). This proved not to be true. Numerous well test simulations showed that production rates between 1,000 bopd to 2,000 bopd would give the necessary pressure-versus-time results to do the classical pressure transient analysis. This discovery indicates smaller facilities and storage are required. In other words, deepwater testing can be done less expensively, and in less time.

During simulation studies, the operating steering committee suggested looking at fluid injection tests. A representative set of injection well test simulations (fluid injection and pressure fall-off) yielded the same results as production and build-up tests.

The second part of the study identified eight well testing systems that can be used in deep water. The results and the sheer volume of data produced, have formed the basis for a software tool that will assist to make more informed decisions on well testing and reservoir characterization. A template of an algorithm for this tool, showing the equipment needs for each well testing system, was developed. This algorithm takes megabytes of information and arranges it so that engineers planning a deepwater well test can select a system, identify equipment requirements, and with the addition of costing data/estimates, will be able to define and cost out the entire well test design. It will match each reservoir type, so that certain options can be eliminated or others more closely considered. This tool will provide engineers (i.e., either training for deepwater operations or well test design) with invaluable information and guidance not publically available in such an integrated format.

This study evaluated deepwater well testing for the GOM and shows eight possible well testing systems, with a focus on risk reduction. Finally, it is clear that, in some cases, there may be a better way (i.e., risk and cost reduction) to do deepwater well tests via injection tests, using the self-standing riser concept. Only future testing will confirm this. Further information on the project can be obtained at http://www.rpsea.org/08121250102/.