Do Your Horizontal Wells Deliver Their Expected Rates?
- M.M. Levitan (BP plc) | P.L. Clay (BP plc) | J.M. Gilchrist (BP plc)
- Document ID
- Society of Petroleum Engineers
- SPE Drilling & Completion
- Publication Date
- March 2004
- Document Type
- Journal Paper
- 40 - 45
- 2004. Society of Petroleum Engineers
- 5.7.2 Recovery Factors, 4.3.4 Scale, 2.4.3 Sand/Solids Control, 1.6 Drilling Operations, 3.3.1 Production Logging, 5.8.6 Naturally Fractured Reservoir, 3.3 Well & Reservoir Surveillance and Monitoring, 2 Well Completion, 5.1.1 Exploration, Development, Structural Geology, 6.5.3 Waste Management, 2.4.5 Gravel pack design & evaluation, 5.5 Reservoir Simulation
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This paper presents the results of comprehensive analysis of BP horizontal-well productivity and completion performance data. The study was performed to benchmark the performance of existing horizontal wells with a view to developing simple, empirical techniques that could be used for predicting the performance of future wells. The developed correlation predicts a range of expected well productivities for future wells. This prediction reflects limitations in current completion technology and possible reservoir heterogeneities. The analysis method is based on presenting the existing well-productivity data in the form of dimensionless parameters---the well-productivity coefficient and the normalized productivity improvement factor (PIF). The results of this study can be used to:
- Sense check the theoretical well-performance estimate for undeveloped discoveries with the historical performance for similar reservoirs.
- Provide quality control for newly commissioned wells to see if performance is as expected.
- Help optimize development well design (i.e., high-angle vs. conventional) for reservoir exploitation.
- Offer a means to rank well-surveillance work based on what the initial well performance is with respect to global historic experience.
Now a well-established technology, the application of horizontal wells has added significant value to oil and gas field development in terms of increased recovery/reserves access and the improved well rates that they can offer. Their applications are well understood, with notable examples being the improved drainage of naturally fractured reservoirs, better recovery from oil rims in gas fields, and the production of heavy oil.
While their application is well understood on a conceptual level, the performance actually delivered by this well type is not as clear, which leads to uncertainties as to the suitability of this well type for individual reservoir development. Similarly, while numerous theoretical, analytical, and numerical models exist to predict performance, there is an absence of an empirically based correlation derived from actual field data. If such a technique were available, it would help to better understand many of the uncertainties that govern horizontal-well performance, in terms of both predictive capability and benchmarking actual field results with the historic track record.
Works published in 19951 started to address this issue. Using well rates as the measure of success, these papers demonstrated the huge rate gains obtained in comparison to vertical offsets. This analysis was supported by an impressively large data set---230 fields yielding information on 1,306 wells. Fields were broadly categorized into "conventional," "heavy oil," and "fractured." In this analysis, the fractured reservoir category indicated the largest rate gains (up to a 12-fold increase), while the conventional category yielded a more modest 4-fold increase.
With an ever-increasing usage of horizontal wells, at approximately the same time, BP identified the need to better understand how successfully horizontal wells were being applied around the world. While considerable work on horizontal well targeting and performance was being performed at an individual field level, no generic metrics existed to benchmark performance between different fields. Therefore, a study was initiated to perform cross-field/basin comparisons, focusing only on initial well productivity. In this study, no attempt was made to address the issues of recovery, sweep efficiency, etc.
The objectives of this work were to:
- Develop simple methods for horizontal-well productivity prediction and uncertainty estimation for future wells.
- Quantify the productivity benefits of horizontal wells in comparison to vertical ones.
- Understand the impact of completion techniques, particularly those involving potential sources of additional productivity damage (screens, gravel packs, etc.).
This paper discusses the methodology and the results of the study's first two objectives in depth.
Several parameters are used to characterize well productivity; the simplest is the well rate. However, the well rate depends on pressure drawdown, and it is difficult to relate the productivity of different wells with well rates1 because the rates have to be related to the same pressure drawdown. For this reason, the well-productivity index (PI), defined as the well rate per unit of pressure drawdown, is often used to characterize well productivity. Well PI, however, is the appropriate characteristic for comparing the productivity of wells from the same field. When wells from different fields are involved, as in this study, well PI is not the right characteristic because it depends on reservoir characteristics (formation permeability) and fluid properties as well as on the type of well completion, geometry, and damage. For this reason, we use another characteristic in the current study that we call the well-productivity coefficient, Cwp. This coefficient is an attempt to remove the influence of reservoir and fluid properties and to present the well PI in dimensionless form. When working with field units, the well-productivity coefficient is defined as follows.
Here, L=the length of the well completion exposed to the reservoir (net penetrated sand length open to the well).
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