| Abstract |
During the 2016-2017 drilling campaign, one injection well and three production wells were completed at both Kawerau (KA55 and KA56) and Rotokawa (RK35 and RK36) geothermal fields in New Zealand. These four wells were drilled in high temperature reservoirs to ensure adequate injection capacity and fluid supply to the Kawerau power plant and adequate fluid supply to the Nga Awa Purua power plant generating about 100 MWe and 138 MWe respectively. The losses and drilling breaks observed while drilling were good indicators to identify qualitatively the feedzones of the wells. However, these types of information were not sufficient to quantify the strength of the feedzones (i.e their Injectivity Index) and translate it into well capacity, especially when total loss conditions were encountered. This quantification is usually done with a completion test which implies to stop drilling and pull-out the drilling tools to run a PTS tool. Once the data or gathered and analysed, the decisions to TD the well or start a sidetrack can be taken. This waiting time on data and the cost associated with it can be reduced using a tool measuring the pressure in the well while drilling. A methodology was derived during this drilling campaign to provide an estimate of the Injectivity Index (II) of the wells and the wells capacity in real-time while drilling. This methodology used the PWD data (annular and pipe pressure) obtained from pressure sensors located in a sub in the drillstring close to the drill bit, for each depth drilled into the reservoir section of these wells. The computation of the II and the wells capacity while drilling enabled the TD decision to be based on more quantitative information and with less waiting time on data. This methodology followed a two-steps process to translate the PWD data first into injectivity information then into well capacity information. The first step calculated the Injectivity Index (II) of the well per depth drilled using the annular pressure of the PWD tool, the loss rate into the well and the reservoir pressure. This II depth series gave information on the depth of the feedzones and the well total II of the well. This approach was cross-checked with a second approach using the PWD data recorded at two different loss rates. The second step converted the II data into well capacity under operational conditions using an in-house wellbore modelling tool. For the injection well, the change in mobility of the fluid between the drilling conditions and the operational conditions was taken into account by calculating the formation Injectivity Index called II’. The capacity of the injection well was then simulated for the hot brine conditions at the maximum Well Head Pressure achievable by the station. For the production well, the II was translated into a Productivity Index (PI) to take into account the reduction in formation permeability due to the heating of the formation and the change in fluid phase under operational conditions. The capacity of the production well was then simulated at the minimum Well Head Pressure achievable by the well to provide the fluid at the appropriate separation pressure for the station. This methodology thus provided two results, a continuous II monitoring and a well capacity range while drilling. These results were very valuable information for determining well success and for decision making during drilling. They informed decisions to drill deeper based on risk of interference, on permeability evolution in the reservoir, they informed decisions to side-track a well and also to TD the well as the targeted II and well capacity were achieved. The comparison of the results of this methodology with post drilling tests shows these results are conservative whilst giving reasonable estimates of the flowrates obtained once these wells are connected to the stations. Further work is needed to improve this methodology for the future make-up wells. One area of improvement is the underestimation of the II with this methodology compared to the completion test II, the other area is the calculation of losses under partial losses conditions. This paper describes the different elements of the methodology used to interpret the PWD data into II evolution and well capacity. It describes how these two types of information were used to add value to the drilling decisions and how these results compare with post-drilling tests. It highlights the limitations in the usage of this PWD methodology to inform the continuation of drilling during the drilling operation and provide suggestions to improve the quality of information obtained with this methodology. |