Drilling operations within the Volga-Urals oil and gas province have a history of drilling problems manifested in partial and total losses of drilling fluid. As a result of these challenges, the companies developing and operating oil and gas fields within the region encounter the following: Significant nonproductive time (NPT) losses and additional financial costs (Urdaneta et al. 2015)Low-quality casing cementing operations proven by sonic cement-bond logging (CBL)Costly remedial cementing and sidetracking or redrilling operations because drilling ahead is no longer possibleWell abandonment, etc. Large-size particle-bridging materials are not efficient for blocking thief zones with wide fracture openings or vast cavernous intervals because they exceed the size of bridging material (Canson 1985). Technologies based on a different principle are necessary to enable efficient plugging within fractures of such thief zones (e.g., special-purpose cement-slurry-based fluid systems with distinctive thixotropic properties developing high gel strength in a short time to assist in controlling and to help reduce drilling fluid losses of any magnitude). During 2016, in cooperation with the operating company, a decision was made to conduct pilot field trials of a new method. The new special-purpose thixotropic cement slurry used within the Volga-Urals oil and gas province is a fluid characterized by low content of solid abrasive particles and by unique rheology. This slurry becomes fluid as soon as shear is applied to it and remains fluid while in dynamic state, such as when pumping downhole or circulating in an averaging tank. While shearing force is reduced, slurry viscosity increases. This fluid forms an internal gel structure after a short static period followed by intensive gelling and gel strength (shear force) development. The slurry can be squeezed into the thief zone through the bottomhole assembly (BHA), saving tripping time (Urdaneta 2016). Plug slurry density can be adjusted from 1.2 to 1.8 g/cm3 for service temperature within the 38 to 110°C range, perfectly matching virtually all downhole conditions within the region (Duffy et al. 2017). This thixotropic cement slurry formula has a simple composition and dissolves well in water using a dedicated averaging tank provided with a circulating mixing system. Owing to distinctive thixotropic properties of the slurry, its performance at downhole conditions (temperature and pressure) is verified using laboratory high-pressure/high-temperature (HP/HT) consistometer testing (on-off-on mode). The on-off-on test helps clearly define how thixotropic properties of the lightweight thixotropic slurry manifest during the operation. Signature features of this test are distinct spikes in slurry consistency (Bc) recorded on the thickening diagram after a short static period. At the same time, this thixotropic cement slurry is easily reversed to a fluid state by resuming circulation or by applying some shearing force to it. After waiting on cement to harden, the cement stone possesses relatively high strength, reaching up to 300 psi, which helps resume drilling ahead as soon as fluid losses are reduced. The new technology has been used for multiple fields of the operating company's with positive outcomes (i.e., fluid losses mitigated completely or partially). The cement slurry demonstrated rapid gel strength development in downhole conditions, with fluid losses reduced for one or two operations. As a result, the operator decided to proceed with the rollout of this method. The primary limiting factor for its use is the 15.9-m3 volume of the averaging tank necessary to mix the thixotropic cement slurry. Advantages of the thixotropic cement slurry used for lost circulation control include: Mixes easilyCan be pumped through BHA with telemetry tools and drill bitFeatures high gel strength and relatively high compressive strength when setLow content of abrasive particles These features help efficiently reduce drilling NPT associated with lost circulation problems. The first pilot operations completed within the Volga-Urals oil and gas province of Russia demonstrated high process performance and cost efficiency.

This article describes the application of relatively high-density foamed cement for cementing wells in the Volga and Urals region. Good cementing practices with high density or conventional density cement slurry is required to ensure mud displacement in fluid saturated intervals of reservoir formations (Benge et al; 1982). With this requirement met, the cement column should circumferentially cover the annulus at this very interval which is exposed to the highest loads. However, due to limited physical and mechanical properties of conventional cement slurries in both liquid and solid state, in certain cases conventional slurries do not solve the problems encountered by the Customer, namely elimination of annular flow between the casing and cement sheath. High-density foamed cement is considered as an improved alternative to conventional cement slurries, and results in a high quality and durable sealing of gas and oil saturated production zones for the life of the well. Proprietary software and process equipment are used for the mixing of the foamed cement slurry with a variety of foaming properties. This process enables the use of a base cement slurry with higher density (up to 2.1 g/cm3) for delivering foamed cement slurries in a wide range of densities. To avoid possible cross flows behind the casing, pilot tests were conducted, where a conventional cement slurry (1.80–1.90 g/cm3) was replaced with a high-density foamed cement slurry with equivalent density with a foam quality of approx. 10% making the cement sheath elastic with improved adhesion to both the casing string and the formation (Spaulding et al; 2018). Pilot tests, incorporating the cementing of several production casings, were conducted where only foamed cement slurries with various foam quality were used in the entire cementing interval. No conventional (non-foamed) cement systems were used in these cases.

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Summary Most wells drilled in 2015–2017 in the Volga-Ural Region of Russia experienced serious downhole problems related to mud losses, which account for a substantial share in total non-productive time (NPT). With conventional methods such as cement plugs, etc. used to solve the lost circulation problem, it takes on average 4 to 6 days per well, or 6 to 10% of the total rig time. In some cases, however, the losses are so heavy that there is no mud return to surface at all, and it may take up to 30 days (about 50% of the rig time) to stop these disastrous losses. Besides, there may be several thief zones at different depths with different loss initiation points. Conventional methods of lost circulation control generally fail. In many cases, conventional cement plugs used to stop mud losses are inadequate to meet such challenges. This paper describes the application of special cryogenic equipment and chemicals to offer oil and gas well operators an alternative solution based on foaming base cement slurries, spacers, and drill muds with inert gas (usually nitrogen) over a wide range of densities. When cementing is used for controlling lost circulation, computer-based simulation is essential to determine hydraulic model parameters. A new proprietary cement service performs high-precision foam cement calculations based on actual well data. The key is to select the correct concentration of nitrogen in foam water spacer and foamed cement to reduce hydrostatic pressure below the point at which losses are initiated in a weak horizon (formation). This special foam cementing equipment is capable of controlling nitrogen concentration automatically and injecting nitrogen into base cement with the foamer to maintain the design density of foamed cement. Cement and service water are foamed under high pressure on the surface in a high-pressure pipeline loop system. Automatic foaming means that three main units are simultaneously in operation: a cementing unit, an N2 unit, and an automatic chemical injection skid. Foamed cement is pumped under pressure to drilling tools. Similarly, service water is foamed to produce foam water spacer with a density of 0.3 g/cm3 to 0.9 g/cm3, which is injected into the well before foamed cement. Foam water spacer is injected first in the thief zone followed by foamed cement. The high-viscosity foam water spacer prevents foamed cement from being washed away by formation fluid and reduces the flow of formation water in the thief zone. As a result, the linear velocity of foamed cement in the lost circulation horizon is reduced, which makes it possible for the cement to achieve the required consistency and isolate the weak formation in the near-wellbore area. Foam water spacer injected into the well lowers hydrostatic pressure and raises the static level of fluid in the well to the wellhead to help ensure returns to surface. The new technology has proved to be the most efficient among other solutions used to mitigate or eliminate mud losses during well drilling in the Volga-Ural region. Foam cementing has reduced the time required to address loss-related problems to two days. This paper discusses the case study of foam cementing used to resolve the lost circulation problem by plugging the thief zone with foamed cement.

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