"Well Placement for maximum production in the Norwegian Sea": Case Study: Norne C-segment Oil Field

• Main Author: Akpan, Stella Eyo
• Other Authors: Kleppe, Jon, Rwechungura, Richard W., Norges teknisk-naturvitenskapelige universitet, Fakultet for ingeniørvitenskap og teknologi, Institutt for petroleumsteknologi og anvendt geofysikk
• Format: Master Thesis
• Language: English
• Published: Institutt for petroleumsteknologi og anvendt geofysikk 2012
• Subjects: ntnudaim:7454; MSG1 Petroleum Engineering; Reservoir Engineering; Norwegian Sea
• Online Access: http://hdl.handle.net/11250/239931

In petroleum fields, the essence of well placement is to develop and maintain petroleum reservoirs in order to achieve maximum production for economic benefit. Maximum production can be achieved with more oil wells, but few optimal numbers of wells in good location reduces economic costs and increase recovery. The best location for the placement of oil, gas or water wells depends on reservoir and fluid properties, well and surface equipment specifications, as well as economic parameters [1].The objective of the study is to determine the net present value from few well placements in the Norne C-segment reservoir by either obtaining the same or more oil production/recovery compared to the base case wells. New well placement in a reservoir simulation model uses an industrial standard ECLIPSE reservoir simulator. Manually simulation approach is used to locate high oil saturation grids for the new well placement. From the base case simulation result, a total number of thirteen wells were discovered, nine producers and four injectors. The production and injection wells were classified with a suffix according to the production templates B, D, K and injection template C respectively.The base case wells removed and new well placed from exhaustive simulation runs for two different scenario cases. A total number of ten wells, six producers and four injectors were placed in each scenario. In order to obtain maximum oil recovery, the producers are placed horizontally while injectors remain the same as those from the base case. The new well placements in the scenario cases are identified with the suffix P-H for producers and I-H for injectors. Simulation results, the total oil produced for wells in each field case from the start year 1997 to December 2015, (end of production) can be seen in Table 10, 11 and 12 in chapter 6. The cumulative oil produced from each field case is the same as the total oil produced from all the wells in each case. The cumulative field oil and gas production from the start of production, November 1997 to December 2015 is 41.3 million Sm3 oil and 260 million Sm3 of gas for base case, 42.8 million Sm3 oil and 269 million Sm3 of gas for scenario 1 case, 43.2 million Sm3 oil and 272 million Sm3 of gas for scenario 2 case. The recovery factor for base case is 28%, scenario 1 & 2 are 29.0% and 29.3%. Each field case uses drive mechanisms, gas injection and water injection to support oil production and maintain pressure in the each field case. The total gas and water injected in the base case field were 9.6 billion Sm3 and 78.8 million Sm3 respectively. In scenario 1, a total of 8.6 billion Sm3 of gas and 81.6 million Sm3 of water was injected and in Scenario 2, 8.6 billion Sm3 of gas and 81.3 million Sm3 of water was injected. The Net present values for the three cases were calculated taking into account the economic costs such as well cost, cost of gas and water injection. Sensitization was done on the oil price ($25, $35 and $45). The NPV results from Table 19 prove that all case projects are acceptable, but scenario 2 is the most economical as it has the highest NPV of $4,026 million based on $35-medium oil price that was considered.