Drilling through depleted sands can result in a multitude of problems such as lost returns, differential sticking, difficult logging and/or not being able to reach the target depth. Often curing lost circulation can be difficult and costly as a result of associated nonproductive time and escalating mud costs. Remedies such as cement plugs, squeezes, expandable liner and casing while drilling can be costly solutions. The use of fluid management techniques, team efforts and proper engineering have lead to the development of an innovative approach to prevent problems and avoid the complex processes of curing mud losses and freeing stuck pipe. This new preventative approach with water-based mud has been applied in several fields, while drilling through a series of highly depleted sands and has proven to be very effective in preventing differential sticking and mud losses. Although operationally successful, the geomechanics and the fluid design resulting in these successes are not well understood. A geomechanical analysis indicates that two mechanisms might contribute to the success:The near wellbore region is turned into a non-porous rock because the particles in the new mud tend to block the pore spaces. The theory of poroelasticity indicates that fracturing pressure is increased by reducing the difference between mud pressure and the pore pressure immediately behind the borehole, which for non-porous rock is zero.Because of this blockage, it is possible that the near wellbore rock strength is increased. This strengthening effect decreases tangential stress and increases fracturing pressure. The geomechanics model can be used to define the operational limits of various mud weights with proper drilling fluids design. This model would enable a consistent and focused approach on drilling fluid design to effectively mitigate massive fluid losses associated with drilling through severely depleted sands or in narrow pore pressure/fracture gradient environments. Introduction Lost circulation has plagued drilling operations throughout history. Generally the types of formations that are prone to lost returns are cavernous and vugular, naturally occurring or induced fractures, unconsolidated sands, highly permeable and highly depleted tight sands. Well known lost circulation control techniques such as bridging, gelling and cementing are typically used, with varying degrees of success. These remedies can sometimes complicate the problems associated with lost returns. Attempts to cure lost circulation can be difficult and costly, especially when considering the associated non-productive time. The lost circulation problems related to drilling through depleted sands are compounded by the low fracture gradient in the sands and the high mud weight required to minimize compressivefailure in the adjacent shales. For depleted sands, the best way to manage lost circulation is to prevent rather than cure the problem. This can be achieved using a combination of a geomechanics and a fluids approach. A literature survey indicates that significant work had been done in this area [1–13]. Lost prevention materials (LPM) were developed to increase fracture initiation or fracture propagation pressure. Recently, a theory of using stress cages to increase fracturing resistance has been developed and demonstrated successfully in the field[2]. Sand bridging or "smearing effect" that is generated by casing while drilling techniques has also been applied[4].
TX 75083-3836 U.S.A., fax 1.972.952.9435. AbstractTraditionally, Oil Base Mud (OBM) has been used by a major operator to drill horizontal wells in the Magellan Strait, Argentina. The operator was faced with additional challenges when drilling an exploratory well due to environmental concerns in a highly sensitive area and evaluation problems related to the use of OBM. Significant advances in water based drilling fluid design in the recent years have allowed water-based drilling fluid performance to approach that of OBM. This presented the operator and drilling fluids supplier with the opportunity of evaluating the application of water base drilling fluid on this well. The planning stage included laboratory testing, review of historical data and an evaluation of experience with similar shales in the area. A high performance water base drilling fluid containing both clay and shale stabilizers, an ROP enhancer and sealing agents was selected to drill the well. This paper presents the laboratory and field data generated during this project. The well was drilled through notoriously troublesome shales to total depth without the wellbore stability problems associated with more conventional water based muds. Gas kicks were controlled with no fluid solubility problems and the fluid exhibited excellent properties even when pressure parameters escalated higher than planned, requiring a higher mud density and high degree of temperature stability. The operator's expectations were met in this very difficult well including minimization of bit balling, near gauge hole and improved ROP in conjunction with optimum hydraulics.The evidence gathered on this project shows that a properly designed water base mud is a viable alternative to OBM in areas where environmental restrictions and formation evaluation problems are a concern.
Drilling through highly depleted sands can result in a multitude of problems such as lost returns, differential sticking, difficult logging and/or not being able to reach the target depth. Often curing lost circulation can be difficult and costly as a result of associated nonproductive time and escalating mud costs. Remedies such as cement plugs, squeezes, expandable liner and casing while drilling can be costly solutions and are not always successful. The use of fluid management techniques, team efforts and proper engineering have lead to the development of an innovative approach to prevent problems and avoid the complex processes of curing mud losses and freeing stuck pipe. A newly developed deformable sealing agent can be added to a water-based fluid at 2 to 4% volume. It is a modified liquid insoluble polymer that is designed to reduce pore pressure transmission by internally bridging the pore throats of the low permeability sands and shale micro-fractures. These bridging and sealing characteristics will help protect the formation where lost circulation may be encountered. This effective bridging enhances the effective rock strength, hence increasing the formation fracturing resistance. A geomechanical analysis indicates that two mechanisms contribute to the success:The near wellbore region is turned into an altered rock because the particles in the new mud tend to block the pore spaces. Stress analyses using rock mechanics theory indicate that fracturing pressure is increased by increasing the tangential stress around the borehole resulting from the ‘enhanced’ mechanical properties of the altered zone.Because of this blockage, it is envisaged that the near wellbore rock strength is increased. This strengthening effect increases the bulk and tensile strengths of the altered rock and increases the fracturing pressure. This paper will highlight field case histories supported by preliminary laboratory work and geomechanical studies indicate that mud losses associated with severely depleted tight sands can be reduced with the use of the newly developed deformable sealing technology. Some of the field accomplishments of this "internal mud cake" as a bridging/sealing approach are: improved drilling curve, lower well cost, stable and gauge hole, reduction in mud losses and differential sticking and reduction in NPT Introduction Drilling through shallow, highly depleted sands is prone to severe lost returns and differential sticking. Lost circulation and differential sticking problems related to drilling through depleted sands are compounded by the low fracture gradient in the sands and the high mud weight required to minimize compressive failure in adjacent shales. Therefore, drilling deeper to reach new targets in mature fields is becoming more attractive and often presents technical and economical challenges. Designing a well in such complex geological settings often results in additional casing intervals and/or the use of expensive expendable liners or casing while drilling. Typical lost circulation control techniques are costly and may not be applicable. It is better to manage lost circulation by preventing the problem, rather than attempting to cure it. A literature survey indicates that significant work has been conducted on wellbore strengthening[1–13]. Prevention methods have been developed to increase fracture initiation and fracture propagation pressure. Recently, a theory of using stress cages to increase fracturing resistance has been developed and demonstrated successfully in the field[2]. Sand bridging or "smearing effect" that is generated by casing while drilling techniques has also been documented[4].
In early 2008, Total E&P-USA sidetracked the Mississippi Canyon 243 #A2 well on its "Matterhorn" TLP, in deepwater Gulf of Mexico. A pre-project geomechanics study identified that the mud weight/fracture pressure window in the depleted and highly unconsolidated 'A' reservoir was very narrow, creating a strong potential for mud losses during drilling and cementing the 7" liner. The risk of losses was a primary concern since the well would be frac-packed, and if a competent cement column did not reach a sufficient height, the ability to fracture the reservoir would have been compromised. To mitigate this risk, the decision was made to drill through the depleted reservoir using a 'flat rheology' synthetic-based fluid, engineered with a high concentration of bridging particles to impart a strengthening effect on the formation. The 'designer fluid' allowed the reservoir to be drilled through successfully, and the 7" liner to be run and cemented with full returns. Analysis of the frac-pack data showed that the formation breakdown pressure was lower than the wellbore pressures experienced while drilling and cementing the liner, suggesting that the designer fluid improved the fracture resistance of the formation. The results imply that using such a designer fluid can have a strengthening effect on depleted/unconsolidated formations, in which some operators have had limited success applying wellbore strengthening techniques. The implication for the industry is that this technique can and should be considered on wells with similar challenges and risks as the Matterhorn A2 well. This paper will describe the approach taken in the laboratory for the fluid design, as well as operational practices to apply the treatment on location. A post-mortem analysis will compare formation breakdown pressures taken from the fracturing operations to actual wellbore pressures experienced while drilling and cementing, to demonstrate that a strengthening effect was realized. Introduction Total E&P USA conducted sidetrack operations on the A2 well to restore production that was impaired after prolonged shutdowns due to Hurricanes in recent years. The operations included: re-entering, de-completing, side tracking and re-completing the well. The operations were done with a heavy work-over rig installed on the TLP, and used a 'flat rheology' synthetic-based mud (SBM). A geomechanics study had been conducted prior to the sidetrack, and the analysis identified that a strong potential existed for mud losses in the depleted and highly unconsolidated 'A' reservoir due to the mud weight required (and associated ECD) to control the breakout of the cap rock shales above - a common scenario faced by operators during in-field drilling operations. According to the study, the mud weight/fracture pressure window had essentially disappeared.
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