Well testing is performed to determine formation
productivity/deliverability, permeability, reservoir pressure, presence of skin damage, flow profile inside a formation and wellbore, reservoir geometry/size/drainage area, inter-well communication, and perforation efficiency.
Well testing is usually performed right after a well is completed and when the productivity does not follow the expected trends. Well testing is also done periodically through the life of a well and field to assess well performance and to establish pressure and rate decline patterns.
In pressure transient testing, the changes in pressure, temperature, and fluid properties caused by sudden changes in production rates of oil, gas, and water from a well (or wells) are measured and analyzed during a given time span. The most widespread type of pressure transient testing is a pressure buildup test in which a producing well is shut-in, and the pressure values are recorded with time. In a pressure drawdown test, a shut-in well is opened, and the pressure values are recorded with time.
The basic requirements of a well test are:
• Measuring the flow rate of the gas and the liquids produced or injected
• Controlling and adjusting the flow from the reservoir • Measuring the pressures and temperatures using
sensitive and accurate downhole instruments • Obtaining samples of the reservoir fluids
• Safely disposing of or storing the well effluent produced during the test
Well Test Design
In a well test design, all the production history and the available reservoir and wellbore properties of a well are included in a pressure transient testing design model. A given reservoir flow geometry based on the completion and production history is selected to simulate pressure and time data as close as the actual data which would be obtained from an ensuing well testing. For the unknown parameters, sensitivity runs should be conducted to cover the entire range of the expected values. Test duration and types should then be modified to provide a sufficient amount of data to be recommended for the ensuing pressure transient testing.
Types of well tests include closed chamber or surge test with the zero-emission FasTest® system, shoot and pull test, drillstem test, cleanup test, slug test, early production test, multi-rate production/ injection well tests, reservoir limit test, permanent gauge test, and interference/pulse tests. For these tests to be reliable and effective, a well test design is critical to assuring the test objectives are feasible by selecting: • Proper completion equipment
• Pressure gauges with the required sensitivity and accuracy
• Type of well test
• Flow rate and choke sizes
• Duration of flow and shut-in periods
The following well and reservoir models are considered when designing or analyzing well test data:
• Analytic and numeric models
• Homogeneous or dual porosity formations • Horizontal, vertical, or deviated wellbores • Hydraulic fracture wellbores
• Any boundary configuration
• Radial and linear composite reservoirs • Layered reservoirs
• Wellbore with limited entry (partial completions) • Changing wellbore storage and/or skin
• Turbulent flow and tidal effects • Well interference effects
• Simultaneous analysis of a changing reservoir model before and after a stimulation or a workover application • Material balance effects
The accuracy and the value obtained from a well test design depends on the following:
• Experienced engineers performing the service • Availability of advanced well/reservoir models • Comprehensive well test design report
• Comparisons with prior tests to establish trend • Parameter sensitivity evaluation to signify the
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Features
• The following features are included in a well test design report:
– Optimum test times – Optimum flow rates
– The right equipment suited for the job
– Models with sensitivities to reservoir, fluid, and wellbore parameters
– Well test procedure
• A well test design is a planned activity that uses the pre- well test well and reservoir information to optimize the test type, procedure, and time
• Success of a well test is greatly enhanced by coupling the well testing with the real- time operations (RTO)
Inputs
Wellbore data, reservoir data, fluid properties, stimulation treatment, information geology, seismic and environmental controls, surface facilities, previous production/injection problems
Well Test Analysis
A well test analysis report provides information about well productivity/deliverability, formation permeability, reservoir pressure, amount and type of damage, perforation efficiency, and flow type /profile inside a formation and wellbore. If the test was designed and conducted for a longer period, then reservoir geometry/size/drainage area and inter-well communication would also be evaluated and provided in the report. Well test and completion data can be deployed to get a more accurate reservoir description.
In a well test report, Halliburton engineers identify opportunities to improve well performance, which often includes reservoir and well production projection with recommendations to enhance productivity. If a well test identifies wellbore damage, then productivity improvement projections will be simulated to compare acidizing with hydraulic fracturing and frac pack to evaluate if stimulation will improve production. If the cause of the problem stems from partial completion and perforation plugging, then re- perforation, acidizing, and fracturing cases will be compared. The optimum production scenario based on the evaluated reservoir and wellbore parameters can also be included in the report.
Well test analysis can provide initial reservoir pressure (pi), permeability thickness (kh), and skin (S). Additionally, the perforated wellbore length (hw), distance of horizontal wellbore to bottom of formation (Zw), and ratio of vertical to radial permeability (kZ/kr) are calculated for horizontal wells. The dual-porosity flow model provides values for λ and ω. Stimulated wells are characterized by the fracture half-length (Xf), conductivity (CFD), and fracture skin. Distances to boundaries and the boundary type (no-flow, constant pressure, or leaky) can be provided for any of the models. In a composite reservoir, the size and the properties inside and outside of the composite zone will be provided. In a limited entry well, the effective interval producing into the wellbore and the plugged perforations are identified. In layered reservoirs, permeability, skin, pressure, and flow rate for each layer can be calculated.
A well test analysis technique may include one or a combination of the following methods:
• Conventional linear regression analysis • Type curve analysis
• Non-linear regression • Closed-chamber DST analysis
Halliburton well test analysis service differentiating factors include:
• Experienced reservoir engineers performing the service • Customized and easy to use report
• Advanced well/reservoir models
• Analytic and/or numeric analysis techniques
• Real-time analysis capabilities using a secured website that can be accessed using your computer anytime or anywhere
Features
• Enhanced reservoir and completion description with advanced and sophisticated reservoir models
• Evaluation and/or analysis performed in batch or real time
• Recommendations for well improvement based on reservoir, wellbore, completion, and the surface equipment
• Fast turnaround at a reasonable cost to free up valuable engineering time
• Experienced reservoir engineers available for any questions
• Evaluation of the entire job
• Follow-up briefing on analyses results and recommendations for future tests
• A complete analysis report with: – Well test description
– System evaluation – Discussion of each event – Gauge comparison – Analysis results – Well test data summary
– Historical comparisons (when applicable) – Production improvement recommendations
(when applicable) – Conclusions
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Multi-Layered Analysis
In multi-layered reservoirs, hydrocarbon fluids exist in different layers. These layers could be located close or far from each other, in hydraulic communication or totally isolated from each other, and with similar or completely different properties. The pressure values in the layers could differ by just the hydrostatic head pressure difference or be totally different from each other. Multi-layer formations are divided into two main categories of:
• Commingled layered reservoirs – The layers in a commingled formation are isolated from each other and do not communicate in the reservoir. They are
hydraulically connected with each other through the wellbore
• Cross-flow layered reservoirs – The layers in a cross-flow reservoir communicate with each other through both the formation and the wellbore. At any point in the reservoir, the interlayer cross flow is proportional to the pressure difference between the layers
At high flow rates, the high permeability layers produce at higher flow rates than the low permeability layers, and thus, they get depleted at a faster rate. At low flow rates or when the well is shut-in at surface, fluids from the low permeability layers invade the high permeability layers which were depleted more.
Halliburton provides a multi-rate, multi-layer test in conjunction with the production logging service. Layer pressure and flow rates are evaluated by the production logging service. This information is fed into the multi-layer well test analysis program to evaluate permeability, skin, and pressure for each layer.
Multi-rate test showing analysis results accounting for turbulent flow effects.
Permanent Gauge Analysis: History plot of pressure and rate showing analysis model match
Reservoir shape: Analysis results showing geologic boundary configuration
Inflow and outflow pressure—rate responses for various reservoir parameters showing production match point.
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Skin vs. Rate
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0 20 40 60 80 100 120 140
History plot (Pressure [psia], Gas Rate [Mscf/D] vs Time [hr])
4500 BHP [psia] Gas Rate [Mscf/D] 5500 Analysis Results
Prod Index = 4.95 Mscf/D - psi Storage Constant = 0.00509 STB/psi True Skin = 1.96
True Delta P Skin = 71 psi Turb Skin = 4.58 Turb Delta P Skin = 165 psi Turb Factor = 0.00131 1/Mscf/D Initial Pressure = 6000 psia kh = 141 md-ft k = 4.7 md 2 -1000010002000300040005000600070008000900010000 Skin 4 6 8 10 12 14 Rate [Mscf/D] HA L7687 9000 0 1000 2000 3000 4000 5000 6000 4700 4800 4900 5000 BHP [psia] Gas Rate [Mscf/D]
Pressure [psia], Gas Rate [Mscf/D] vs Time [hr]) Pressure vs Time
Pbar
Gas Rate vs Time
HA L7688 3,000 ft 3,000 ft 2,500 ft 2,000 ft HAL7755 0 2000 2000 3000 4000 5000 6000 7000 8000 9000 Constraints: Erosion:C=100.00 Outflow Parameter Inflow Parameter FORM PERM (md) 50 50 100 100 250 250 SKIN ( ) 0 5 0 5 0 5 FLNCHOK ID (1/64 ) 12 16 20 26 36 64 4000 6000 8000 10000
Production Data Matching Theoretical Model
FLOW RATE bbl/d FL O WIN G BTM PRE S psig Match Point HA L7689 Inputs
Test objectives, geologic information, prior production data, completion schematic, fluid property data, prior treatment data, well test downhole pressure gauge files, well test surface data report files