Maximising Rate and Reserves from Existing Wells - A Wellhead Compression Strategy for Large Onshore Brownfields
Authors: Headland M. K. , Gunawardena P. , Chipperfield S. T. , Mabarrack D. 
Published: October 2016

Abstract
As a result of the major investment in LNG (Liquefied Natural Gas) plants in Queensland, gas demand in Eastern Australia is expected to triple by 2017 when compared with 2014 demand (Office of the Chief Economist, 2015). This presents the opportunity to increase recovery from existing mature gas fields in Eastern Australia. While satellite and field nodal compression are common place for reducing field pressure and improving both production and reserves, the distance between centralised compression and some wells can be large, resulting in a pressure drop that limits the production potential from the well. Wellhead Compression (WHC), located at the well lease can be used to minimise this pressure drop, maintain high utilisation of existing compression infrastructure, and maximise reserves for a given well. This paper highlights how implementation of a WHC program with an accompanying management strategy has been applied to over 500 wells to deliver over 10 MMscf/d incremental rate and 70 Bcf of reserves with attractive economics and low capital expenditure when compared with new drills.
WHC installations can add significant reserves and rate and are typically installed when a well is approaching abandonment rate. The WHC can remain on the well for the remaining life and, once production ceases, be moved to another well.
This paper provides a case study for the successful application of WHC in a mature gas field, comprising a combination of conventional and tight gas reservoirs with over 600 producing wells and provides a methodology for determining:
Well candidate selection & unit selection type
The operator developed a methodology for WHC candidate selection based predominately on production data, reservoir properties, fluid properties and well completion type, with the primary objective being to lift wells above the Minimum Rate to Lift Liquids (MRTLL – Turner, Hubbard 1969) to enable stable production at lower pressures. This, in conjunction with parameters such as expected line pressure also enabled selection of unit type to ensure optimal economics.
Unit type design & selection
By working with one compressor packager and adopting proven concepts from North American production operations, the operator developed four standard unit types that can be applied to a vast majority of wells in the target basin. This resulted in significantly reduced engineering work, faster procurement without re-tendering and better operations integration. Multiples of the standard unit would be deployed where higher capacity was required.
Overall fleet management strategy to optimise fleet performance
The operator presents a unifying strategy, utilising expected well life for wells within the target basin to forecast the ultimate number of units that are required to achieve optimal rate, reserves and economics.
Reserves growth
Conventional analytical methods such as Rate Transient Analysis (RTA) and integrated production modelling are appropriate for estimating reserves growth as a result of WHC implementation. Additionally, a methodology is proposed to capture changes to developed and undeveloped reserves on the basis of WHC implementation, recognising that units will service multiple wells in various fields over their effective life.
The operator has successfully applied WHC in a mature gas basin consisting of tight gas and conventional sands. The methodology presented can be applied to other fields, including unconventionals, to determine the applicability of WHC and develop an optimal field management strategy.