Low-Permeability Black Oil/Gas Condensate Reservoirs Using - PowerPoint PPT Presentation

Analysis of Short-term (Flowback) and Long-term (Online) Production Data from Low-Permeability Black Oil/Gas Condensate Reservoirs Using Analytical/Semi-Analytical Methods C.R. Clarkson University of Calgary

Outline  Introduction  A few facts  Problem statement and objectives  Methods  Modification of pseudovariables  Iterative integral  Dynamic drainage area  Special Application of RTA Methods:  Fracture Height Estimation  Future Work  Conclusions Slide 2

Introduction  Fact:  When producing from MFHWs completed in ultra-low permeability reservoirs:  a complex series of processes occurring at multiple scales are initiated that we don’t completely understand Extent of Induced Contacted Horizontal Hydraulic Reservoir Area Well Fracture Network Perforations 1000 m+ Slide 3 From: Clarkson et al. (JNGSE, 2016)

Introduction  Fact:  When producing from MFHWs completed in ultra-low permeability reservoirs:  a complex series of processes occurring at multiple scales are initiated that we don’t completely understand Reactivated Natural Fractures Matrix with fine-scale Matrix with Nanopore structure Matrix laminations and interspersed organic of organic and fractures and inorganic matter inorganic matter Induced Natural Hydraulic Fracture Fracture meters micrometers centimeters nanometers millimeters A STYLIOLINA 0.5 mm Slide 4 From: Clarkson et al. (JNGSE, 2016)

Introduction  Fact:  Reservoir characterization methods that account for the appropriate physics are in their infancy Pore Confinement Effects Multi-Phase Flow Complex Fracturing Gas phase Condensate phase Hydraulic fracture Free gas Adsorbed gas Velocity ≠ 0 C? B Zone A p i p d Pressure p w Distance from hydraulic fracture etc.  Understanding how to advance characterization methods is critical for sustainable development through primary and enhanced recovery processes Slide 5

Introduction  Reservoir and Hydraulic Fracture Characterization: Analysis Category Development Stage Analysis Type Properties Derived Seismic, 2D, 3D Pre-Drill Reservoir Sample k m , k f , S o , S g , S w , k ro , k rg , k rw , ρ m , ρ b , ø m , PSD, Analysis PTD, P c , a, m, n, OM, IOM, R o , G c , E s , ν s Drill/Post-Drill k m , k f , h, S o , S g , S w , ρ b , Log Analysis ø m , ø f , PSD, OM, IOM, E D , ν D Reservoir and Pre-Frac Welltest kh sys , P closure , P reservoir Pre-Frac Hydraulic Fracture (DFIT) Characterization Frac Monitoring Frac geometry, SRV Frac Treatment (Microseismic) Flowback kh f , kh sys , P breakthrough , Analysis x f Post-Frac Frac Modeling x f , A c , F cD Post-Frac Welltest kh sys , x f , A c , F cD (F/BU) Production kh sys , OGIP/OOIP , Long-Term (Online) Analysis CGIP/COIP , x f , A c , F cD Production Slide 6 From: Clarkson et al. (JNGSE, 2016)

Introduction  RTA – Flowback/Online: From SPE 166279 Slide 7

Flow-Period Illustration of Flow-Periods Flow-Regimes Flow Period Illustration of Flow Periods Flow-Regimes ASSESS DATA VIABILITY STEP 1: Introduction X-Section View Plan View X-Section View Plan View Gather Reservoir, Review Well History Review Production Data Completion and PVT Data  RTA – Flowback/Online: Flowback: Flowback: Depletion (Fracture) Depletion (Fracture) CHECK FOR DATA STEP 2: Before Breakthrough Before Breakthrough CORRELATION of Formation Fluids of Formation Fluids (single-phase flow in (single-phase flow in PRELIMINARY fracture) fracture) STEP 3: DIAGNOSIS Review/Edit Data Filter Data for Clarity IDENTIFY FLOW STEP 4: Flowback: Flowback: REGIMES Transitional Transitional After Breakthrough After Breakthrough of Formation Fluids of Formation Fluids PERFORM STRAIGHT- STEP 5: (multi-phase flow in (multi-phase flow in LINE ANALYSIS fracture, single or fracture, single or multi-phase flow in multi-phase flow in Obtain Preliminary Obtain Preliminary Obtain Preliminary formation) formation) Estimate of Estimate of Reservoir Estimate of Hydraulic Hydrocarbons-in-Place Permeability Fracture Properties PERFORM TYPE-CURVE STEP 6: ANALYSIS Long-Term Production: Long-Term Production: Linear Flow Linear Flow Validate Reservoir Validate Hydrocarbons- Formation Fluid Formation Fluid Validate Hydraulic Permeability Estimate in-Place Estimate Fracture Property Production Dominant Production Dominant Estimates (multi-phase flow in (multi-phase flow in fracture, multi-phase flow fracture, multi-phase flow in formation) in formation) PERFORM FORECAST STEP 7: WITH MODEL FIT EMPIRICAL MODEL STEP 8: Slide 8 TO FORECAST From: Clarkson et al. (TLE, 2014)

Introduction  Problem Statement:  Analytical solutions used in RTA commonly assume: • Single-phase flow of liquids • Static reservoir and fracture properties • Darcy’s Law is valid • Constant rate or pressure production • ….. Slide 9

Introduction  Objectives: 14  Develop approaches that account for: Pore Confinement Effects Phase Envelope of a Gas-Condensate Fluid Under Confinement Mean Pore Pressure = 0.19 MPa Unpropped Fracture Gas (N 2 ) 50 12 • Mean Pore Pressure = 0.53 MPa Multi-phase flow 45 Mean Pore Pressure = 0.88 MPa 40 “Dewpoint 10 • Permeability (D) Stress-dependent fracture and matrix properties Suppression” 35 Mean Pore Pressure = 1.23 MPa Pressure (MPa) 8 30 • Pore confinement effects: non-Darcy flow 25 • 6 Free gas 20 Pore confinement effects: fluid properties 15 Adsorbed gas 4 10 5 2 Velocity ≠ 0 0 -150 -100 -50 0 50 100 150 200 250 300 350 400 0 Temperature ( o C) 0 10 20 30 40 50 pore width = 300 nm pore width = 10 nm pore width = 5 nm pore width = 2 nm Effective Stress (MPa) Slide 10

Methods  Multiple Approaches to Account for Non-Linearities: • Modification of pseudovariables • Iterative integral method • Dynamic drainage area Slide 11

Methods: Modification of Pseudos • Linearization of governing PDE 1.Linearization Technique • Using Pseudovariables • Pseudovariables calculations 2.Method of Calculation • Saturation pressure relationship • Liquid solution 3.Backward Modeling • Validation Image Courtesy of Hamid Behmanesh Slide 12

Methods: Modification of Pseudos  Calculation procedure: model inversion - linear flow analysis (2P flow – JNGSE 2015, SPE 172928)  Linearization Pseudopressure Pseudotime Liquid Solution Analogy! Images Courtesy of Hamid Behmanesh Slide 13

Methods: Modification of Pseudos  Calculation procedure: model inversion - linear flow analysis (2P flow – JNGSE 2015, SPE 172928)  Pseudovariable Calculations: Image Courtesy of Hamid Behmanesh a p p p PVT S o (1) (2) (5) (3) (4) Slide 14

Methods: Modification of Pseudos  Calculation procedure: model inversion - linear flow analysis (2P flow – JNGSE 2015, SPE 172928)  Pseudovariable Calculations: G inv. p Image Courtesy of Hamid Behmanesh N p p t a t G inv. Material Balance G p (1) (2) (3) (4) (5) (6) (7) Slide 15

Methods: Modification of Pseudos  Calculation procedure: model inversion - linear flow analysis (2P flow – JNGSE 2015, SPE 172928)  Inverse Modeling  Infinite-acting linear flow solution - CP Images Courtesy of Hamid Behmanesh Slide 16

Methods: Modification of Pseudos  Application: model inversion - linear flow analysis (2P flow – JNGSE 2015, SPE 172928)  MFHW, tight (lean) gas condensate reservoir 60 10000 4800 Oil Rate Gas Rate Water Rate pwf Gas Rate (Mscf/D), Oil, Water Rate (STBdD) Condensate Gas Ratio Water Gas Ratio Flowing Bottomhole Pressure, psia 50 CGR and WGR, STB/MMscf 1000 3600 40 100 2400 30 20 10 1200 10 Constant CGR 1 0 0 0 100 200 300 400 500 0 100 200 300 400 500 Time, days Time, days Slide 17

Methods: Modification of Pseudos  Application: model inversion - linear flow analysis (2P flow – JNGSE 2015, SPE 172928)  MFHW, tight (lean) gas condensate reservoir 2.0 1/q gas , 1/(q oil ) versus √t Inverse of Gas Rate, 1/(MMscf/D) Cartesian x f √k * = 21.5 ft.md 0.5 1.5 m CP coordinates Initial 1.0 x f √k Properties Distance of Material Balance Investigation 0.5 p 0.0 f CP 0 5 10 15 20 Square Root of Time, days 0.5 Slide 18

Method: Iterative Integral  Calculation procedure: model inversion - linear flow analysis (2P flow – JNGSE 2013; 2016 and SPE 167176)  Integrate non-linearities over the domain  (c) 1 m ( p )  Image Courtesy of Farhad Qanbari w m t 0.95 CP f ( p ) q c w o Bubble point pressure 0.9  1 1 g ( m ) 0.85 1    D : dm  D f ( m ) 0.8 0 f c c D D 0.75    ˆ   ˆ        exp 2 d d        0.7 0 0 ( m erfc ( ))       D D dS o /dp = 2 10 -4 psi -1 m g 1 .   D  ˆ   dS o /dp = 1.75 10 -4 psi -1   ˆ      0.65 exp 2 d d   dS o /dp = 1.5 10 -4 psi -1      ( m erfc ( )) 0 0 D D 0.6 m D   Initial guess : erfc ( ) 1000 2000 3000 4000 p w (psi) Slide 19