RIASSUNTO
Abstract
Due to reduced availability of high quality reservoirs, more wells require stimulation. The current default method for stimulation is hydraulic fracturing, using either proppant or acid to keep the fracture open. In many environments, Proppant or Acid Fracturing is a good solution to increase productivity. Some of the unresolved challenges with fracture stimulation are reservoir related such as the uncertainty about whether the fracture will grow through different reservoir layers, potentially contacting unwanted water. Operational challenges are environmental, cost, operational complexity and availability of equipment and competent personnel. Onshore fracturing experience can build on the learning of hundreds of wells to optimize the fracture stimulation process, but this is not possible in an offshore environment.
A new completion based stimulation solution is developed to be simple and efficient without environmental impact and with significantly lower cost than current solutions. Several reservoirs have been simulated to investigate the long term production and recovery using the method. The relatively new well geometries require further understanding to apply the technology. A study on offshore well cost has been made.
Introduction
An attempt for a definition of fishbone wells is given in Schlumbergers Oilfield Glossary; ""A series of multilateral well segments that trunk off a main horizontal well. The appearance closely resembles the ribs of a fish skeleton trunking off the main backbone.?? Other definitions include that the fishbone laterals penetrate the same reservoir as the motherbore.
Current multilateral systems allow drilling laterals in sequence. The laterals are most frequently completed as branches near to horizontal due to drilling technology limitations. Reservoir engineers often prefer to penetrate vertically to connect intervals (Jia 2004) due to low vertical permeability. The productivity effects of short vertical branches will provide a similar vertical flow path as hydraulic fracturing, if an appropriate density of the laterals can be achieved. The appropriate density (spacing of the vertical laterals) is a function of the reservoir permeability.
The system is under development and is awaiting a field trail.
Description of the system
A reservoir liner is equipped with short subs connected to full length 12 meter (40ft) liner joints. The subs are positioned at well depths where stimulation is desirable. Each sub contains 4 small diameter tubes (needles) with length up to 12 meter. The total number of needles is variable, but typically 100-200 needles can be accommodated within an offshore environment. One end of the tube is axially displaceable in a seal penetrating the liner sub at a deflection relative to the mother bore. This end of the needle has a nozzle pointing against the wellbore. The reservoir liner hanger slips are set and pumping through the liner hanger is started, in a similar way as a liner cement job. The pumped fluid jets out of the nozzles at the end of the needles and the formation ahead of the needle is jetted (abraded) away. Positive pressure inside the liner applies on the cross section of the needle which acts like a hydraulic piston. The needle continues to penetrate the rock until the needle extends fully. After pumping, the liner hanger is set and upper completion is installed and finalized.
The needle with the nozzle is left in the newly jetted lateral. The needle may be chemically removed after the operation. The well can be flowed back and produced like any uncemented liner. In a mechanically stable formation, the lateral can produce through the annulus of the needles and into the main wellbore. The main wellbore is completed open hole, and will produce reservoir fluids in addition to the laterals.