A multi-disciplinary approach is preferred when addressing this challenge. However, all ideas related to the two themes in this challenge are welcome. Both incremental and radical ideas are welcome.
Infill drilling is an important measure for increasing oil and gas recovery. For several mature fields, however, drilling and completion of new wells are a challenge due to a non-existing or very limited operational drilling window. This is caused by the field’s production and injection history and is particularly related to reduced pressure and temperature.
Reduced pressure and temperature in a complex reservoir (i.e. high degree of compartmentation and barriers to vertical flow) may result in a mix of zones with different degree of depletion. Pressure depleted zones will have both the pore pressure and the stress reduced while temperature reduction (due to cold water injection) is only reducing the stress.
Most fields are likely to be restricted by the depletion challenge; either in the mature production phase or in the gas blowdown phase. This may result in less optimal well solutions, or in worst case, no new wells. Improving the ability to drill through severely depleted reservoir zones will increase the oil and gas recovery. In addition, it will reduce the need for choking back existing production, in order to avoid further depletion in areas with future drilling.
In the DPN IOR strategy update in 2016, it was identified that approximately 20% of DPN’s IOR volumes are connected to infill drilling where we have depletion challenges, and the number is expected to increase.
The operational drilling window is determined by difference between the fracture gradient and the maximum pore pressure gradient. The operational drilling window will vary throughout a wells life as a response to pore pressure and temperature changes. Bore hole stability also plays a role in determining the drilling window.
Traditional drilling practices rely on maintaining a pressure in the annulus to prevent formation fluid from entering the borehole and at the same time avoid fracturing of the formation being drilled, which could lead to a loss situation. In addition to the static pressure from the fluid column in the wellbore, dynamic forces are in effect as the drilling fluid is circulated (ECD) and the drill string is moved up or down (swab/surge).
A risk based approach is required to optimize well design, operational efficiencies and well delivery. The wellbore stability plot (figure 1) is the starting point, but it does not, on its own, give the full risk picture. An exact and complete understanding and prediction of the curves is not possible by a purely theoretical approach and any workflow that only focuses on this, without including experience data for calibrating the model will fail in delivering a reliable framework from which good decisions can be made.
A reduction in pore pressure (depletion) leads to a reduction in horizontal stress and consequently a reduction of the fracture gradient.
The magnitude of the horizontal stress can be measured by hydraulic fracturing techniques. The most common test type is the Extended Leak-off Test (XLOT) (figure 2) where a small fracture is first created. The fracture closure pressure (FCP) is equivalent to the minimum horizontal stress.
According to our technical requirements the minimum stress gradient shall be established and verified by systematically testing of the formation by extended leak off tests. For fields in production, the XLOT requirement only applies if the stress gradient has not yet been determined. Testing requirements to determine the number (and type) of XLOT tests shall be established in the well data acquisition strategy document with input from rock mechanics and field development personnel. A cost-benefit and risk analysis shall be done and documented to assess if the XLOT test shall be performed or not.
An extended leak off test is perceived as costly (min 3 hours rig time) and may introduce well stability risks. The result of the cost-benefit and risk analysis is therefore often that the test is not performed. Data points to narrow down the fracture gradient uncertainty are therefore sparse.
The main challenge to drill a depleted reservoir is our fear of losing drilling fluid or cement slurry to the formation – lost circulation.
Risks include loss of well control, well control incident, lack of cement integrity, technical sidetrack, shallow set TD/casing/liner, wellbore breathing, stuck pipe, loss of reservoir productivity, formation collapse and underground blowout.
There are three main classes of lost circulation:
Lost circulation usually occurs in wells with narrow operational window and in weak points such as:
Although rigorous planning and operational procedures to prevent and cure losses have been established, our understanding of loss mechanisms and effect of Lost Circulation Materials (LCM) to cure and/or stop losses is perceived to be inadequate. LCM normally involves adding a coarse blend of carbonate particles, either in small volumes as a preventive measure or as a massive “pill” to cure losses by sealing off fractures and other openings in the formation.
In weak zones with naturally open fractures or extensive permeability lost circulation may occur at pressures below the fracture gradient. In this case, the loss resistance will be dependent on the pore pressure gradient and not the fracture gradient.