Underbalanced Drilling Model Simulates Dynamic Well Bore Conditions

Zhihua Wang, Erlend Vefring, Rolv Rommetveit
RF-Rogaland Research
Stavanger, Norway

Taco Bieseman
Shell Research & Technical Services
Rijswijk, The Netherlands

Roberto Maglione
Agip S.p.A.
Milano, Italy

Antonio Lage, Edson Nakagawa
Petrobras
Rio de Janeiro, Brazil

Underbalanced drilling simulators (UBD) can optimize dynamic flow conditions to maintain underbalanced well bore conditions.

This conclusion in a series of two articles that began June 16, 1997, describes how a simulator can utilize operating inputs for liquid flow and gas injection rates to control pressure fluctuations.

A dynamic UBD simulator, developed in a joint industry project involving RF-Rogaland Research, Norske Shell, Norsk Agip, and Elf Petroleum Norge, is used for the purpose of preplanning UBD operations.

The simulator incorporates models for multiphase flow, well-reservoir interaction, gas/oil solubility, and gas injection systems.

The fluid components in the system include injected gas, mud, produced gas, produced oil and water, and rock cuttings.

Both coiled tubing and conventional jointed pipe can be simulated.

It can analyze a variety of operational situations that cannot be performed with a steady-state simulator, including circulation, gas injection, drilling, tripping, drillpipe connections, and bottom hole assembly (BHA) deployment.

Two field cases are presented here: The first case is a coiled-tubing drilling operation in the Dalen field, The Netherlands, where a nitrogen-lift test was conducted in a through completion.

The second case is a UBD operation in the Candeias field of Brazil, where drillstring injected gas tests were conducted within 95/8-in. casing.

A UBD operation is a complex operation that requires careful planning. It is important to maintain an underbalanced condition throughout the operation, taking operational restrictions into consideration.

Restrictions include maximum allowable injection rates, minimum allowable flow rates, and operational limitations of the mud motor.

Procedures for drillstring movement, start-up and shutdown of fluid injection, and pipe connections should be designed so that excessive wellhead pressures and accidental situations of overbalance are avoided.

A stable operating range must be achieved so that well pressures are not overly sensitive to changes in normal control parameters, including gas injection rates and reservoir drawdown.¹

It is important to predict the amount of injected gas required for UBD.

Careful planning in a UBD operation requires a competent dynamic simulator. Outputs from the simulator must be tested by comparing simulation outputs with empirical field measurements.

There are underbalanced drilling software tools available,2 including in-house software; however, they only calculate well bore pressure for static or steady-state conditions.

Dynamic effects from circulating start-ups and shutdowns, tripping, and gas injection, cannot be modeled by these programs.

In this article a brief presentation of the simulator is given. A more comprehensive discussion may be found in References 3-6.

Physical system

The physical UBD system is shown in Fig. 2 [31023 bytes], Part 1 of this series (OGJ, June 16, 1997, p. 55). Drilling fluids (liquid, gasified liquid, or foam) are pumped down through the drillstring, through the downhole drilling motor and bit, and then up the annulus.

Within the annulus, drilling fluids are mixed with rock cuttings, production fluids (gas, oil, or water), and injected gas which are fed into the annulus through a parasitic string (supplementary casing or tubing).

The mixture of fluids flows into the formation if the well bore pressure is greater than the formation pressure.

While drilling underbalanced, the annulus is normally closed off with a rotating blow out preventor (BOP), and the fluids and cuttings flow up and out of the well through a choke line.

During a trip, circulation may or may not be required to maintain an underbalanced condition. It may be necessary to fill up the hole by pumping liquids through the choke or the kill line.

When a conventional rotary rig is used, periodic establishment of circulation during a trip may be required to increase the hydrostatic pressure or compensate for lost circulation.

Simulator applications

The factors which cause dynamic situations include:

• Variations in drilling fluid pump rates

• Variations in gas injection rates

• Variations in production rates caused by well bore pressure changes and/or local reservoir depletion

• Variations in production rates from increasing open hole length

• Drillstring movement

• Pipe connections

• Unexpected events (gas supply interruptions).

If steady-flow conditions are interrupted (connections, tripping), the well bore will be subjected to pressure fluctuations upon recommencement of gas injection and fluid circulation.

Well bore stabilization is a serious problem for maintaining an underbalanced condition as discussed in Part 1 of this two part series.

During the planning phase, the simulator is used to:

• Determine if it is possible to achieve underbalance for the given system under operational constraints

• Evaluate options for achieving underbalance

• Calculate injection rates and volumes

• Design operational procedures for tripping, drilling, and connections so that excessive wellhead pressures and accidental overbalance situations are avoided

• Design the operation so that it is in a stable operating range.

Simulator inputs and outputs

To solve the set of governing equations which define the output calculations (see equation box), a finite-difference method is used.

A fixed grid is laid on top of the flow network (drillstring, well bore, parasite string), and fluid flows are then defined by finite-difference representations for each specific governing equation.⁵

Mass conservation equations are integrated over each grid. Velocities and pressures are computed at the grid boundaries.

An important aspect is that a front-tracking technique is applied to the solution. This means that inter-mud fronts as well as the beginning and ending parts of the gas flows are tracked.

Front tracking eliminates problems with artificial diffusion of the numerical solution. Significant improvements and modifications have been carried out to the program to simulate the physical system and to simulate cases where there are lengthy well bore sections in contact with the reservoir.⁴

These developments include annular gas-injection systems, two-phase flow inside drillstrings, increasing well depth because of drilling, and bit movement from tripping and drilling.^{5 6}

The simulator runs on any UNIX work station with an X Window System, graphical user interface, and Motif user interface. The simulator will eventually run on personal computer systems.

The simulator software package consists of five parts.

Units selection: The user can select any unit type to meet specific requirements. A total of 36 unit categories are defined. When a complete selection has been made, it can be saved for later use. All calculations in the simulator core are carried out in SI.

Preprocessor: The preprocessor is used to set up or modify input data. The data are divided into 15 groups. Each group has one or more windows containing relevant input fields.

Simulator core: The simulator core contains algorithms for solving the mass and momentum conservation equations and calls to sub-models. It requires inputs from the control panel, and the results are outputted to the control panel and saved within files.

Simulation control: The user controls and monitors the simulation through the control panel. The simulator runs in an interactive mode.

Post-processor: The post-processor reads the output files generated during the simulation. The user can display the various physical parameters graphically, and can make hard copies. The files can be exported to spreadsheet software programs.

Annular string case study

For the first case study, the Dalen 2 was selected in the eastern part of The Netherlands.

This well was originally shut-in after gas production had declined to 1.06 MMscfd.⁷

The lower section of the well was abandoned, then side-tracked into the upper part of the reservoir.

A 5-in. liner was cemented-in, completed, and then a christmas tree was installed.

Before drilling cement, a nitrogen lift test was conducted, making it an ideal candidate for a simulation study.

Annular injection of nitrogen was conducted in-between the 75/8-in. casing and 5-in. completion strings. A side-pocket mandrel positioned at 985 m (3,232 ft) measured depth (MD) served as the conduit.

Well bore parameters and simulation inputs for the Dalen 2 are shown in Table 1 [11294 bytes] or Table 2 [10593 bytes].

The well geometry consisted of a vertical section to 2,500 m (8,202 ft), followed by a deviated well profile to 3,000 m with an inclination of 60?.

Table 3 [28250 bytes] shows the mud and injection rates for four runs and compares the pressure readings (choke and bottom hole) of the field data with outputs from the simulator. Record 1 compares data based on mud flow rates only. Records 2-3 compare data for both mud flow rates and nitrogen injection.

In the case where there was no nitrogen injection and only mud flow (Record 1), agreement was within the range of 0.33%, and underestimated the bottom hole pressure (Pbh) by only 1 bar.

For the cases where there were simultaneous mud flow and annular nitrogen injections (Records 2-4), the simulator consistently over-predicted the Pbh, but relative errors remained less than 5%.

Over-prediction became larger for higher gas injection rates and smaller for decreasing gas injection rates.

For instance, in Record 2, the mud rate was 50.7 gpm and the injection rate was 500 scfm. From these inputs, the simulator predicted a Pbh of 263.5 bar, while the field reading recorded 251.3 bar. The simulator overestimated the result by 12.1 bar (4.85%).

In Record 4, the mud rate was increased to 52.8 gpm and the injection rate was decreased to 400 scfm. In this case, the simulator predicted a Pbh of 265 bar, whereas the field reading was 255.5 bar. The simulator overestimated the result by only 9.5 bar (3.72%)

Because of the large annular volumes in-between the 75/8-in. casing and 5-in. completion strings, changes in nitrogen injection rates at the surface did not immediately produce flow changes at the injection point downhole.

This parameter was ignored in the simulation program and the model assumed that there was an immediate flow change at the injection point. However, at the time of this writing, it has been incorporated into the simulator.

Because of the uncertainty of the actual annular gas injection rates, and the 5% accuracy rating of the Pbh gauge, these simulation results were regarded as satisfactory and verified the accuracy of the simulation model.

Drillstring case study

Candeias field is located in the southern part of the Reconcavo basin, in northeast Brazil.

In this field, oil is stratigraphically trapped in four zones consisting of sandstone, fractured shales, and fractured carbonates.

The fourth zone, comprised of fractured carbonate rocks, is the most important in terms of oil production.

A major drilling problem in this area is lost circulation, making this well a candidate for UBD.

Unfortunately, there was a lack of equipment for handling oil produced during the UBD process, and the well was not drilled underbalanced.

Instead, the drilling program established an operational overbalance margin of 1.5 ppg.

In early 1995, conventional drilling of well 7-C-218-BA began. At 1,788 m (5,866 ft), a few meters above the third zone, 95/8-in. casing was set (Fig. 1 [26947 bytes]).

Anticipating the possibility of lost circulation, it was decided to drill ahead with nitrogen foam.

Before drilling the cement inside the 95/8-in. casing, measurements of the circulating Pbh for various liquid and gas injection rates were recorded.

The drillstring was run into the well with pressure and temperature sensors at 1,757 m (5,764 ft).

It took more than 33 hr to run these tests. Liquid injection rates varied from 60 to 300 gpm and nitrogen rates from 350 to 1,500 scfm.

Well bore parameters and data for simulation inputs are given in Table 4 [10514 bytes] and Table 5 [11930 bytes].

Five different combinations of mud and Nitrogen rates were selected for simulation. The recorded and simulated pressures at 1,757 m (5,764 ft) are compared in Table 6 [20219 bytes].

In this case, the simulated pressures are higher than the measured pressures, and the difference between them increases with increasing gas injection rates.

Fig. 3 shows the comparisons of the RF-DynaFloDrill simulator, and three other simulators in relation to actual measured pressure data.^{6 8}

During the field testing, it was difficult to control and maintain a stable foaming agent within the system.

Existence of foam in the system affects well pressure, and most likely decreases the circulating well pressures.

For a given amount of foaming agent, higher flow rates probably generate more foam than slower rates.

The simulation model does not take foam into account, but will be incorporated into the UBD simulator at a later stage of the joint-industry project.

References

1. Emeh, V., and Bieseman, T., "An Introduction to Underbalanced Drilling," RKER.95.071, report published by Koninklijke/Shell E&P Laboratorium, Rijswijk, The Netherlands, 1995.

2. Misselbrook, J., Wilde, G., and Falk K., "The Development and Use of a Coiled-Tubing Simulation for Horizontal Applications," SPE paper 22822, presented at the 66th Annular Technical Conference and Exhibition of the SPE, Dallas, Oct. 6-9, 1991.

3. Ekrann, S., and Rommetveit, R., "A Simulator for Gas Kicks in Oil-Based Drilling Muds," SPE paper 14182, presented at the 60th Annual Technical Conference and Exhibition held in Las Vegas, NV, Sept. 22-25, 1985.

4. Vefring, E.H., Wang, Z., Gaard, S., and Bach, G.F., "An Advanced Kick Simulator for High Angle and Horizontal Wells - Part I," SPE paper 29345, presented at the 1995 IADC/SPE Drilling Conference, Amsterdam, Feb. 28-Mar. 2, 1995.

5. Rommetveit, R., Vefring, E.H., Wang, Z., Bieseman, T., and Faure, A. M., "A Dynamic Model for Underbalanced Drilling With Coiled Tubing," SPE paper 29363, presented at the 1995 IADC/SPE Drilling Conference, Amsterdam, Feb. 28-Mar. 2, 1995.

6. Wang, Z., Rommetveit, R., Vefring, E.H., Bieseman, T., and Faure, A. M., "A Dynamic Underbalanced Drilling Simulator," paper presented at the 1st International Underbalanced Drilling Conference & Exhibition, The Hague, Oct. 2-4, 1995.

7. Adam, J., and Berry, M., "Through Completion, Under Balanced, Coiled Tubing Side-Track of Well Dalen-2," paper presented at the IADC Well Control Conference for Europe, Milan, Italy, June 9, 1995.

8. Lage, A.C.V.M., Nakagawa, E.Y., de Souza, M.M., and Santos, F., "Recent Case Histories of Foam Drilling in Brazil," SPE paper 36098, presented at the 4th Latin American and Caribbean Petroleum Engineering Conference, Port-of-Spain, Trinidad & Tobago, Apr. 23-26, 1996.

The Authors