What is the ancient carpenter’s mantra? “Measure twice, cut once!” This is good advice that has stood the test of time worldwide for centuries. Why is its lesson so important? Because it is a way to eliminate, or dramatically reduce, risk.
Risk reduction is the name of the game in the oil industry also, and it is more important these days than ever. As oil and gas become harder to find, as plays become deeper and more difficult to drill and produce, as offshore water depths increase, so do risks. Operators need to know for sure the parameters of the reservoir they are about to complete and attempt to produce.
The challenges facing asset managers today can be summarized as follows:
- Extend the plateau and produce more from mature reservoirs
- Explore and produce more from marginal reservoirs
- Expand deepwater development
- Improve the ability to characterize gas reservoirs
- Solve water control and flow assurance issues.
Like the carpenter’s rule, well testing provides accurate, reliable measurements that address these challenges while they directly reduce risk. Consider a deepwater development project. The consequences of not testing can be huge, and can affect profitability in any number of ways. Production facilities can be over- or under-sized, reservoirs can be improperly characterized, and flow assurance issues can manifest themselves. These problems lead to reduced recovery factors, poor well performance, and formation damage that hamper production and/or increase the need for interventions.
Any one of these can turn a promising discovery into a disaster. Schlumberger has been investing in R&D to provide solutions to these challenges, and we are confident that the investment has been worthwhile. Today, test results are far more informative than in the past. And test measurements are far more accurate and comprehensive.
On a macro-scale, using fluid samples, flow rate, and pressure measurements during a well test, we can better characterize the reservoir by discovering boundaries, faults, and fractures, estimating and optimizing well productivity, obtaining reservoir pressure, and most importantly, confirming volumetric reserve estimations. On a micro-scale, we can characterize produced fluid, provide details as to its chemical composition, and give clues about wax, hydrate, or asphaltene content and potential.
With testing, 3D heterogeneity can be delineated. This information is vital to optimize stimulation programs, access bypassed reserves, and increase recovery factors. Testing reacts to formation and fluid heterogeneities that are invisible to seismic, and by definition, discontinuous between wells. These are identified only by their effect on production, but by then it is too late. With modern testing analysis, problems can be identified, characterized, and their long-term effects predicted in advance, before irreversible decisions have been made.
Instant interpretation at reservoir scale
At the wellsite, most test data can be converted to actionable information in real-time. Today, portable multiphase flowmeters measure the flow rates of each phase fraction of produced fluid without the need for a separator. Laboratory quality samples are obtained and analyzed onsite using laboratory-grade measuring spectrometers, and fluid compositional analysis of the samples provides evidence of compartmentalization that could require alteration of completion plans.
At reservoir scale, software programs now link the reservoir seamlessly with the surface production facilities, providing the ability to better predict field performance, to reduce the number of development wells required, and to pinpoint future infill drilling opportunities. Today, each well’s test can be analyzed, history-matched, and interpreted in context with the entire asset’s performance. The effect of any change between the pore and the stock tank can be determined and accurate decline curve predictions made.
Correlations or hard data?
All data can be introduced into a reservoir simulator where “what if?” games can be played to predict the result of a decision before a commitment is made. With dynamic test data, the power of the simulation is enhanced. In addition, because the workflows are linked seamlessly, the results can be introduced into economic programs including discounted cash-flow models that help the operator realize the economic impact of decisions or alternatives under consideration. Hard test data eliminates a lot of the guesswork that was required previously – today’s decisions are based on measurements, not estimations. Well testing provides answers you cannot get any other way.
The only thing risky about testing is failing to do it when necessary. Management needs to know with an increasing degree of accuracy the value of reserves and the cost of accessing and producing them. Investors want better assurances to quantify return on capital before they commit. These questions continue for the life of the reservoir. With your asset in the balance, it is best to be sure.
Hatem Soliman
President, Testing Services
Schlumberger
This page reflects viewpoints on the political, economic, cultural, technological, and environmental issues that shape the future of the petroleum industry. Offshore Magazine invites you to share your thoughts. Email your Beyond the Horizon manuscript to Eldon Ball at[email protected].
