Predicting the gains of deliquification

Transcription

1 Gas Well Deliquification Workshop Sheraton Hotel, February 17 20, 2013 Predicting the gains of deliquification Wouter Schiferli, Jordy de Boer, Erik Nennie (TNO)

2 Project structure and goals Joint Industry Project for 4 parties EBN, GDFSUEZ, ONE, Total E&P Goal: Transfer US knowledge on deliquification to Europe Three phases: 1. Literature search What techniques are applied, and how widely Many common techniques in the US are not applied in Europe 2. Engineering guidelines to predict most suitable technology Implemented as Excel-based tool 3. Quantitative tool Calculate benefits of various technologies Can serve as input to economic screening process 2

3 Need for quantitative analysis Selection methodology yields candidate technologies Actual deployment decision is a balance between: Production and UR gain over time CAPEX/OPEX TNO s expertise lies in modelling Models were implement for a range of techniques Implemented in a GUI for quick screening Calculates modified production profile after implementing each technology CAPEX/OPEX analysis left to operator 3

4 Technologies included in the tool Allow the operator to evaluate the benefit of using Velocity string Gas lift Foam ESP Wellhead compression Plunger lift Eductor Tail pipe Performance measured by Ultimate recovery / abandonment pressure Production profile and required power over time 4

5 Methodology Basic wellbore and reservoir model required Wellbore model calculates BHP Reservoir model Simulates depletion Includes reservoir pressure drop Semi-steady state models describing each technique Goal: translate technique to modified well lift performance Reservoir model is not modified 5

6 Wellbore modelling Correlation required to calculate wellbore dp Deviated wells Variable diameter Many correlations are proprietary, choice was limited Gray standard Gray does not handle deviated wells Beggs and Brill universal OLGA ss proprietary Beggs and Brill was chosen Good match with OLGA Inclinations from horizontal to vertical 6

7 Reservoir modelling Tank (material balance model): With re reservoir drainage radius, and ϕ porosity Pressure drop is modelled using A and F factors: A, F can be calculated from reservoir parameters Ideally should be known from well tests 7

8 BHP Base modelling method Beggs and Brill: tubing TPC at constant WHP Reservoir IPR calculated, including depletion Operation point continuously calculated Loading occurs at TPC minimum End of production Yields abandonment pressure Line P WHP Choke assumed open Depletion Tubing TPC Loading Gas flow 8

9 BHP Modelling mitigation measures Mitigations modelled in different ways Completion (diameter) change: Velocity string Tailpipe Change in boundary condition: Eductor: performance diagrams Wellhead compression: simplified analytical model Other models: V string loading Gas lift BHP is minimized, staying within available power Tubing loading Gas prod ESP liquids are produced by pump through separate string V string TPC Tubing TPC 9

10 Modelling: foamer Assumed to be added continuously Line P Start-up not taken into account Cap-string type of application Foaming mechanism is complex Reduction in surface tension Reduces critical rate to 75% of original rate Foam formation Increases gas-liquid surface area Reduced density, improved liquid transport Further reduction in critical rate to 50% or less Full modelling not feasible Reduction in critical rate is input to the tool WHP Choke assumed open 10

11 Modelling: plunger lift Most effective in smaller tubing (up to 3.5 ) Line P Usually requires installation of new tubing Most effective when annulus pressure buildup possible Low-set downhole packer is unfavourable Production is first assumed to occur through small string When close to loading, plunger installed (see below) WHP

12 Modelling: plunger lift Method developed to compare plunger to velocity strings Calculates a TPC for the plunger lift system Assumptions: Gas influx constant throughout cycle Plunger rise velocity 5 m/s No slip past plunger Based on modified Foss-Gaul guidelines

13 Case: 3.5 vertical well Near-vertical well of 3.5 tubing 500 of 5 liner to perforations Initial P res 340 bar (4900 psia) 22 bar (300 psia) THP LGR 80 m 3 /1e6Sm 3 (14 bbl/mmscfd) Loading observed at 70,000 Sm 3 /d (2.4 MMscf/d) Decision required on mitigation method

14 Output results

15 Brief analysis Various techniques compared on basis of recovery Base case (BC) prediction Loading at 75,000 Sm 3 /d (field: 70,000) Production ends at 100 bar res pressure Gas lift / ESP appear very effective Can produce virtually dry gas Requires high gas lift rates Takes long to obtain high recovery Economics play large role in decision Left to operator BC VS WHC ED ESP FM PL GL TP UR [%] P ab [bara] CGP [10 6 Nm 3 ] Gain [%]

16 Conclusions Tool was developed to predict performance of mitigation measures Based on (semi) steady state models Beggs & Brill pressure drop correlation Reservoir depletion and pressure drop Compressor, pump and eductor models Simplified pump and foam modelling Performance was considered realistic for most wells Beggs & Brill seems less suitable for specific cases LGR >> 100 Larger diameter wells (>4 ) May be solved by implementing different correlations 16

17 Outlook for follow-up programme Improving range of application Further validation against field trials Integrating other common pressure drop correlations Adding additional functionality Improved pseudo-pressure reservoir model Better modelling of first phase of production (e.g. by including a choke model) Intermittent production requires more advanced modelling Coupled dynamic well and reservoir model Models available, but not readily integrated in fast tool Contents of follow-up programme are currently being discussed New participants welcome 17

18 Flow assurance course Date: April 14 17, 2013 Location: TNO, Delft Fundamentals of multiphase flow in flowlines and wellbores Practical Flow Assurance Multiphase dynamics: liquid loading, slug flow Solid deposition, integrity, heavy oil Well control, reservoir inflow Exercises Liquid hold-up in pipelines, severe slugging, slug catcher sizing, etc. Presenters: Prof. René Oliemans (Emeritus, TU Delft) Prof. Ruud Henkes (TU Delft / Shell Global Solutions) TNO Fluid Dynamics To keep updated, contact presenter More details and registration at 18

19 Presenter details Wouter Schiferli TNO Fluid Dynamics Department, Delft, NL T: E: 19

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