| Example Name |
Description |
| 1PtGas |
This example shows the use of the Chase et al. – 1pt Test IPR for a vertical gas well. This IPR curve was developed for predicting the performance of hydraulically fractured gas wells using a single stabilized point obtained from either a pressure build-up or draw-down test. Because the IPR uses data from an actual well test, a completion component is not included in the model. A short flowline is accounted for as well. |
| AutoCalibration |
Auto-calibration feature is shown for a deviated oil well. Only one flow rate is used. A temperature survey is used to compute fluid temperature in the well. This feature enables user to select the best pressure drop correlation by matching the measured pressure survey data. Four wellbore correlations are selected to calculate the pressure drop for the specified rate. Wellbore calibration report indicates Hagedorn-Brown correlation has the best match with the tuning factor of 0.984. Tuning factor close to 1 has the perfect match of the measured pressure survey data. The wellbore calibration plot shows measured pressure data with only the best correlation calculated data.
Different correlations work well under different situations, and this feature allows you to (a) choose the best correlation and (b) adjust any correlation to match actual data |
| Bilateral |
Multilateral Oil well with ‘bilateral’ configuration that includes 2 reservoirs with horizontal wells is modeled. Water cut is different in each formation. Handle cross flow option is checked in the set up dialog. In this case, PERFORM determines which link or layer has the highest pressure. Each of the other links joined at the node is assumed to be experiencing injection until pressure drops to the pressure of that link or layer. This enables user to identify if any layer is really contributing to the total well production. Rate with a negative sign means the link (reservoir layer) is actually injecting not producing. PERFORM allows up to nine different pre defined lateral geometries. Fluid properties, IPR, completion model for each layer can be changed. Each link can have different directional survey. User can create case studies for most of the parameters in a link or layer. |
| CBM_IPR |
A coal bed methane (CBM) well is simulated with a CBM IPR for gas production. Coal matrix permeability is also calculated using two different methods in base case and case 2. The single phase coal gas production is different from a conventional dry gas reservoir because of the effect of matrix shrinkage. Unlike conventional reservoir; permeability and porosity of a Coalbed methane reservoir is a function of the reservoir pressure. Hence, traditional IPRs are not recommended for this. This well has a 645 ft long flowline and outlet pressure is fixed. To simulate this, the wellhead pressure entry is disabled in the wellbore dialog, and this value is calculated by PERFORM. |
| Completion_gun_data |
This example demonstrates the use of perforation gun data to find the optimum perforation length. The example represents a gas well completed with gravel pack stable perforations type model. The perforation length is calculated using data from a gun manufacturer. Perforation gun performance data from several vendors are included in the program. The perforation length for different guns is based on the concrete slab penetration test under surface conditions. This length can be corrected for downhole condition following API 19 B recommendation and the methodology described in SPE 27424. API test data for the selected gun suggests that the average total target penetration would be 8.79 inches under surface conditions. But, when this data is corrected for the downhole effective stress using API recommended method, the perforation length is reduced to 7.34 inches. This capability of the program enables the user to design and evaluate completions more accurately. Five case studies are created by doing wellhead pressure sensitivity as a part of production enhancement strategy. |
| Downhole_pumps |
An oil well is simulated using ESP and PCP pumps: Case 1- ESP, Case 2- PCP, and Case 3- with no pump. The reservoir has 35% water cut with single point test data. So, Vogel corrected for water cut IPR (or composite IPR) is used without any completion component to represent the inflow. This is done because test data already included the completion effects. It is recommended to ignore completions component if the selected IPR uses any test data (single point or 4 point tests). Case 3 represents the natural condition that indicates no production from the well. Horse Power (HP) conversion method is used to calculate the pressure increase due to the pumps at the pump setting depth for ESP and PCP. Case 1 models a downhole ESP with the available HP of 96.4. This shows the well can produce about 900 bbl/d. Case 2 has a PCP with available HP of 13 HP. The well can produce 500 bbl/d with the PCP running at 370 RPM. |
| ESP_performance_curve |
A horizontal oil well is simulated with two different ESP pumps. Pump performance curves are imported (in the Wellbore dialog) from SubPUMP® for the two cases. (SubPUMP is an IHS program that includes a comprehensive equipment database). The base case shows that the well will not produce under natural flow conditions. Fluid properties indicate that this is a volatile oil reservoir. Back pressure IPR is used to represent the inflow. Gomez mechanistic model is used to calculate the deviated wellbore pressure drop for the two phase fluid flow. This correlation can identify the flow pattern and applicable for both vertical and inclined flow lines. Case 2 has an ESP with 335 total stages and case 3 has an ESP with a total of 246 stages. Although producing GLR is about 2920 scf/bbl, but the gas separation (modeled in PERFORM) shows that this is reduced to 258.3 scf/bbl at the pump intake. PERFORM can also model any user-added downhole pump in addition to ESP and PCP, but cannot do design calculations. IHS has SubPUMP to design and analyze the ESP system. These two applications can share files created earlier by importing them in to the program. |
| Example_autocal |
The auto-calibration feature is shown for another deviated oil well. In this example, three flow rates are used to calibrate the wellbore calculation and pick an appropriate correlation. |
| Fractured_pss_gas |
Fractured gas well under pseudo steady state conditions is modeled. Chase et. al. IPR is used to simulate this well because of its radial geometry. This IPR can also be used for radial well producing under transient condition if producing time (right after the fracturing) is known. It can also calculate the radius of the external boundary. Usually, completion component is ignored for fractured well IPR as fracture behavior dominates the completions pressure drop. Maximization (Options menu) is also done on reservoir permeability, skin and tubing ID parameters (with minimum, average and maximum value for each one). This gives the best combination which results in the highest production. ‘Maximization sorted graph’ shows production from each combination of parameters in ascending order. A maximization report shows the solution points for all possible combinations. |
| Gas |
Basic analysis of a Gas well with a wellhead choke. Sensitivity analysis is performed on perforation diameter and liquid yield. Well unloading velocity for condensate and water is entered by the user (Options menu). PERFORM also has three methods to calculate the gas well unloading velocity. It can also show the unloading rate and velocity profile (from the well head up to the bottomhole) in the system report. Gray pressure drop correlation is used because of high GLR sensitivity. |
| Gasfrac_proppant |
An example modeling a vertical gas well during the transient period right after a fracture. The Fractured Well IPR is used along with proppant data from the vendor to increase the accuracy of the model. PERFORM has a built-in proppant menu (accessed from the Reservoir Data screen) containing data on proppants from every major manufacturer. A sensitivity analysis is used to determine which type of proppant will optimize production. |
| Gradient_Gasinjection |
Gas injection well with gradient analysis. Example shows how to compute pressure gradients for the injection gas in the annulus. Sensitivity is done on injection pressure. Gas composition is used to improve fluid data. As dry gas is injected into the well, Fundamental flow correlation is used for the wellbore pressure drop calculation. This correlation is recommended for dry gas or gas with a very little condensate in it. This feature can be used to find bottomhole pressure for a given surface pressure and rate. |
| GasLift_Gradient |
Gradient analysis for well on gas lift. Sensitivity is done on gas valve depth. Well is set to produce 2100 bbl/d under gaslift. Producing GLR (after injection) is entered in the Fluid dialog. The GLR (before injection) is entered in the Wellbore dialog. Chokshi mechanistic model is selected to do tubing pressure drop calculations because of the high GLR and vertical wellbore configuration. Alves et. al. heat transfer model is used to find the wellhead temperature. This model is based on the energy balance equation and is recommended for accurate calculation. Gradient graph suggests that higher injection depth corresponds to the lower BHP (as one would expect for a gaslift well). |
| GasLift_Optimiz |
This feature is useful to find the optimum injection rate, operating valve depth and production rate increase due to gas injection. No completion model is added to the reservoir because measured productivity index is used to represent the inflow. GLR before injection is entered in the Fluid dialog to enable PERFORM to calculate GLR after injection for a certain gas rate. If user enters the existing valve depths (Gaslift parameters dialog) then program will try to find the closest possible operating valve depth from the table. If needed, PERFORM can also calculate the optimum valve depth for the specified injection rate. |
| GasLift_Design |
This example demonstrates the operating and unloading valve design feature for a well with continuous gas lift. The desired liquid rate is 3500 bbl/d with the GLR (before gas injection) is 100 scf/bbl. The well is slightly deviated with minimal flow regime effects. Dun & Ros two phase flow correlation is selected to model the tubing flow. Gaslift installation feasibility study plot suggests that the well will not flow under natural conditions. So, 1825 Mscf/d gas is injected with the operating pressure of 1350 psig. Pressure operated valve design method is chosen. Note that design for fluid operated gas lift valves is also allowed. Injection depth and pressure at equilibrium point is also calculated along with the unloading valve depths. Interactive valve design option is available (where user can change the calculated valve data) in addition to re-designing valves with existing mandrels. |
| GasLift_System |
Nodal analysis for a well on gas lift. Sensitivity is done on total GLR to find the optimum value for gas injection. Darcy- frack pack IPR is used. The Frack-pack is a completion technique in which a small fracturing treatment is combined with a cased hole gravel pack. The fracture is designed to improve the well productivity by eliminating near-wellbore damage and minimizing radial convergence effects. The sized gravel pack is used to prevent sand particles from coming into the wellbore. Completion model is not added to the system since the effect of the completion on the IPR is accounted for with the skin factor. Outflow sensitivity plot shows liquid production rate and the corresponding GLR to find the optimum injection rate (calculated from the GLR and liquid rate). |
| GasPipeline |
Gradient analysis of a 12-mile Pipeline with separator and compressor. Outlet pressure is calculated. Heat transfer is done using correlations. The pipeline is carrying 9500 Mscf/d of gas with liquid yield of 12.5 bbl/MMcf. The compressor was able to boost the pressure by 125 psig (between suction and discharge) with 120 HP and 80% efficiency. Alves et. al. unified heat transfer model is selected to do the energy balance assuming that the pipeline is located on surface of the ground. This model suggests that the temperature will reduce from 80o F to 60o F at the end of flowline from the wellhead. Note that PERFORM can model many equipments like compressors, pumps, separators, etc. |
| Guo_Evans |
In this example, the Guo & Evans IPR is used to model a horizontal fractured gas well. This IPR was designed for horizontal gas wells that intersect multiple natural or hydraulic fractures. It is valid for a rectangular reservoir and fully or partially penetrated horizontal wells. The number of fractures as well as the dimensions and permeability of the fractures are required to complete the model. In addition, a sensitivity analysis is done on the number of fractures to determine how many stages of fracturing are necessary to optimize production. |
| GuoWH |
This example illustrates the use of the Guo- Wellhead Test IPR for oil wells that produce solids. The IPR is based on a wellhead pressure, temperature and total liquid production rate measurements. This IPR was developed for oil wells and based on a mechanistic model originally designed to predict flow of gas, water, oil, and solids. It cannot be used in downhole networks, injection wells, or for annular flow at the surface. Because test data is used, a completion component is not included in the model. |
| HorizontalWell |
System analysis for a horizontal, oil well. Two correlations used for pressure drop in wellbore – Beggs & Brill is used for the horizontal (or inclined) section and Ansari mechanistic model for the vertical section of the wellbore. Reservoir has reached to pseudo steady state condition. So Joshi IPR is selected with a 2000 ft tunnel length. Reservoir skin is entered as zero for the IPR as open perforation completion model is used (to calculate the completion pressure drop around the wellbore) considering pressure drop through the horizontal tunnel. Wellhead choke is also modeled with Perkins correlation for critical & subcritical flow. |
| HydrateFlowline |
Gradient analysis on a gas flowline to show hydrate prediction (part of flow assurance) including inhibitor effect (glycol). User has the option to enter up to three different weight % of the selected inhibitor to view the effect of each concentration. Hydrates are solid materials that form when liquid water and natural gas are in contact, like a gas/oil production system. Even with temperatures above the water freezing point (as high as 85 F (29.4 C)), hydrates can deposit in pipes, causing a blockage or pressure drop. Hydrate graph shows the pressure gradient and the hydrate lines (for each wt %) for a range of temperatures. If the pressure gradient plot crosses any hydrate line then there is a possibility of hydrate formation at the specified pressure and temperature. |
| HydrateWellbore |
Gradient analysis on a gas well to show hydrate prediction (part of flow assurance) including inhibitor effect (methanol). PERFORM has Methanol and Ethanol as inhibitor in addition to the three glycol based inhibitors. There are three models available to predict hydrate formation in wellbore or flowline. Some models use the composition (C7+ included) of the flowing gas to do hydrate calculation. Flow assurance report shows the pressure, temperature and the distance from the inlet where there is a possibility of hydrate formation at a certain wt% of inhibitor. |
| Maximization_completion_heavy_oil |
An oil well with gravel pack stable perfs completions is simulated. Maximization is conducted on completion parameters (shot density, perm ratio and perf length) to find the most suitable conditions for the maximum production. Maximization (from Options menu) allows users to examine production scenarios based on a group of selected variables. It is truly a maximization tool that enables users of PERFORM to generate answers to questions like, ‘How can I maximize production from my well?’ or ‘What will happen to my production if certain well parameters change in the future?’ All the maximization is done based on the constraints set by the user. A Maximization Sorted Liquid Graph and Maximization Sorted Gas Graph show rates in descending order under all possible scenarios calculated based on the constraints. This rate sorting is based on liquid rates for oil wells and gas rates for gas wells. Maximization is only applicable for System Analysis. This procedure is really a permutation of user-supplied variables with only one objective - maximize fluid rate. While Sensitivities can be performed for System, Gradient or Gaslift Analysis, Sensitivities are limited to 5 cases (including base case) while Maximization may have up to 244 cases (including base case). |
| Offshore_heavyoil_pvt |
System analysis on an offshore well producing a very heavy oil (12 API). The Darcy IPR and Open Perforation completion models are used, along with PVT lab data for the produced fluid. If it is available, PVT data can be used in PERFORM (in the Fluid Data Screen) to increase the accuracy of nearly any model. The more PVT data that is available and entered into PERFORM, the closer the model will come to matching the real-world conditions of the produced fluid. |
| OffshoreWell |
An offshore oil well is modeled from the reservoir to the platform (riser outlet). Rigorous temperature calculations are used for well and flowline. Chokshi et. al. mechanistic model is used to do pressure drop calculation in the wellbore and in the riser. This model calculates the liquid hold up and flow pattern throughout the flowline. Users can then anticipate the possibility of slug formation inside the riser. Alves et. al. unified model is selected to do riser temperature calculation as this model considers sea current and temperature profile in addition to the insulation. Future IPR is used in sensitivity to model reservoir pressure decline in future. This is recommended as future IPR considers oil FVF, Kro, viscosity, etc. changes with the pressure decline. |
| Oil_sand_flux |
Flux calculations are introduced as new criteria (other than drawdown limits) to monitor and operate sand control completions. The main purpose of this surveillance system is to estimate the maximum production rate at which a sand control completion can be safely produced. An oil well with cased hole gravel pack completion is simulated to calculate Vc - the average fluid velocity exiting the perforations (at casing ID). System report examines if this operating velocity (solution points) exceeds the recommended critical value. If that happens then the destabilization of annular pack may occur because of excessive downhole flowing velocity from perforations (Vc - at casing ID).
Mechanical skin that is calculated from the pressure transient analysis (PTA) is used to find Vc for different flow rates. PERFORM also can do this skin calculation if PTA data is not available. Fractured well IPR is used to model the inflow. Usually, the only valid completion model for this is gravel pack completions. Flux calculation is limited to cased hole gravel pack completions only. |
| Oil |
Modeling of a vertical, onshore oil well with no flowline. Inflow is modeled with the Vogel/Harrison IPR with the flow efficiency of 1. Completion model is added to separate the completion pressure drop from the reservoir inflow. System graph shows two IPR plots – inflow @ sandface and the inflow only. The later is modeled by subtracting the completion pressure drop from the inflow at sandface (also known as base IPR). If completion is added to the well system then the pressure from Pr (reservoir) to Pws (sandface) is modeled by the base IPR and from Pws to Pwf(bottom hole flowing) is modeled by the completion pressure drop correlation. However, if no completion model is included then Pws and Pwf are the same and the base IPR will be used to represent the entire inflow. |
| ScaleFlowline |
Gradient analysis on an oil flowline to show scale prediction (part of flow assurance) based on chemical analysis of produced water (Oddo-Tomson method). The saturation index (S.I.) for scales is computed based on the concentrations of barium, strontium, calcium, magnesium and sulfate salts to predict the tendency of scale formation. Oddo and Tomson suggest a minimum value of S.I. equal to 0.4 for Scale precipitation. If turbulence is present in the system, this number will be lower. S.I. less than or equal 0 indicates no possibility of scaling. The flow assurance report shows calculated S.I. values for each type scale entire length conduit.</TD> |
| ScaleWellbore |
Gradient analysis on a vertical oil well to show scale prediction (part of flow assurance) based on chemical analysis of produced water (Oddo-Tompson method). |
| SmartWell |
Multilayer well with 3 layers with sub-surface safety valves (SSSV). Fluid properties for each layer can be different. The top reservoir has lower reservoir pressure than the other two layers and is modeled using PI method. Joshi pseudo steady state IPR is selected for middle and bottom layers. The main wellbore is 5600 ft deep. Hagedorn & Brown correlation is used to calculate pressure drop through tubing and the links that connect the reservoirs. Two restrictions are added in the system- one in the wellhead and another at a depth of 7100 ft from the surface. PERFORM may show a message if any restriction is under critical flow because Ashford & Pierce choke correlation selected here is capable of differentiating critical and subcritical flow. The solution point shows the total rate possible from all the reservoirs. Detail solution point data report shows contributions from each layer/reservoir along with the inlet and outlet pressures for each link. |
| TriLateral |
Analysis of a multilateral well with ‹Herringbone trilateral› configuration. |
| TwoLayers |
System analysis for a well with 2 consecutive layers. Sensitivity is done on water cut in second layer. |
| TwoLayers_Sand |
System of analysis for a well with 2 consecutive layers. The first layer produces primarily oil and is modeled with the Darcy IPR, while the second layer produces primarily water. In addition, sand production is predicted using the Sand Production Prediction tool available in the Completion Data screen. This tool can model either shear or tensile failure of the sand and predict producing rates. |
VelocityString
(FlowAnnular) |
Analysis of a gas well with velocity string to control liquid loading. Flow is set as ‘annular’, outside the velocity string. Although this installation is primarily for gas well, sometimes it may be set up for an oil well. This is because the produced fluid is liquid (mainly water) and multiphase wellbore correlation will calculate the pressure drop in either case. If water cut is very high (80 % or more) then dead oil option needs to be selected for bubble point pressure calculation. User can also do sensitivity on velocity string size and depth to find the optimum values. |
VelocityString
(FlowString) |
Analysis of a gas well with velocity string to control liquid loading. Flow is set as ‘string’, inside the velocity string. User can check and compare which flow type would be better for unloading the well. Unloading and erosional rates are calculated and shown in the system graph. Unloading rate should be lower than the solution point rate and must be located on the left hand side of the intersection point in the system graph. On the other hand, erosional rate should be higher than the solution point rate (right hand side of the intersection point) to avoid erosion of the flow line. |
| WaterInjection |
System Analysis case that illustrates how to setup a case for water injection. Oil should be selected as fluid type and dead oil option needs to be selected (Fluid data dialog) with 100 % water cut to model water injection. User can specify the fracture gradient value for the formation in system preferences dialog. PERFORM shows a warning message if the calculated BHP exceeds this gradient. Sensitivity is done on injection pressure to find the optimum injection rate and pressure. Outflow sensitivity graph shows the water rate vs corresponding injection pressure for this well. |