The main objectives in well construction are to maximize reservoir deliverability, reduce remedial jobs, and minimize nonproductive time (NPT) during drilling and cementing. One of the key factors to help maximize reservoir deliverability is the ability to reach the target reservoir depth with a minimum number of casing points and maximum production tubing size for the completion. Losses during drilling and cementing should be controlled to reduce unplanned casing points and minimize the NPT.

These challenges are severe in depleted and low-fracture-gradient formations. Engineered solutions to control loss circulation and to place cement slurry in these environments are presented and discussed. Controlling loss of circulation during well construction is more than just selecting the proper type of lost circulation material (LCM). The engineered solution discussed in this paper correlates the formation and LCM properties for effective control of losses. In situations where LCM alone may not reduce the losses, the use of chemical sealants such as polymers and special cement systems are discussed. The special cement systems can be designed to meet the specific needs such as acid solubility for easy removal, thixotropy, and filtrate loss.

Cement slurry for primary cementing across low-fracture-gradient and depleted formations should be designed to meet the density requirement so that it can be placed in the annulus and losses can be minimized. Ultra-low-density cement slurries, as low as 5.4 lbm/gal, are presented and discussed. Case histories are also presented to illustrate field implementation procedures, and the optimization of cement slurry designs to meet well requirements is discussed as well.

The results presented in this paper can be applied in well construction to control loss circulation and cementing across depleted and low-fracture-gradient formations, which ultimately should help reduce NPT and maximize well production.


Controlling loss of circulation during well construction involves more than just selecting the proper type of lost circulation material. A fully engineered approach is recommended. During the planning phase, this approach incorporates borehole stability analysis, equivalent circulating density (ECD) modeling, leakoff flow path geometry modeling, plus drilling fluid and LCM material selection to help minimize effects on ECD. During the execution phase, real-time hydraulics modeling, pressure-while-drilling (PWD) data, connection flow monitoring techniques, and timely application of LCM and chemical treatments are proving to minimize and in some cases eliminate losses in high-risk areas. After successfully drilling a wellbore, the hole should be circulated and cleaned of the gelled drilling fluid and drill cuttings, and then cement slurry should be pumped to cover the entire annulus. The cementing job should be engineered so that the ECD during cement slurry placement does not exceed the fracture gradient. In addition, LCM should be incorporated into the cement slurry to help control losses. The cement slurry density should be low so that the ECD (hydrostatic pressure + friction pressure) is less than the fracture gradient. While placing the cement slurry, the sum of friction pressure and hydrostatic pressure should be lower than the fracture gradient of the formation.


Prevention of drilling NPT begins with selecting the optimum drilling fluid, i.e. one that exhibits low or fragile, nonprogressive gel strengths. A common characteristic of these fluids is a minimized requirement for commercial colloidal materials and prevention of colloidal-sized drill solids buildup. Both high-performance water-based and invert emulsion fluids that are low-colloid, polymer-based systems are available.1

The use of geomechanical modeling in well planning can provide the safe mud weight window within which the ECD should be constrained. Static mud weight predictions (to mechanically stabilize the wellbore) are influenced by parameters such as in-situ stress and pore pressure gradients, wellbore orientation, and formation material and strength parameters. However, exposure to the drilling fluid could alter the near-wellbore pore pressure and rock strength and can cause progressive wellbore instability. Obtaining an accurate picture of potential issues can require sophisticated wellbore stability simulators that evaluate time-dependent instability developments and account for fully-coupled mechanical, thermal, and chemical effects.2

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