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Dispersants, also known as friction reducers, are used extensively in cement slurries to improve the rheological properties that relate to the flow behavior of the slurry. Dispersants are used primarily to lower the frictional pressures of cement slurries while they are being pumped into the well. Converting frictional pressure of a slurry, during pumping, reduces the pumping rate necessary to obtain turbulent flow for specific well conditions, reduces surface pumping pressures and horsepower required to pump the cement into the well, and reduces pressures exerted on weak formations, possibly preventing circulation losses. Another advantage of dispersants is that they provide slurries with high solids-to-water ratios that have good rheological properties. This factor has been used in designing high-density slurries up to approximately 17 lbm/gal without the need for a weighting additive.
Abstract Managed Pressure Drilling is an adaptive drilling technique used to precisely assess the formation pressure limits and manage the annular pressure profile accordingly. MPD uses a lighter mud density that with assistance of surface backpressure maintain the overbalance condition, and the dynamic adjustment of this surface pressure allows to maintain Constant Bottomhole Pressure (CBHP) in both dynamic and static conditions. Generally, MPD system reduces the extra overbalanced pressure applied on a formation while drilling conventionally Recently, the operator utilized Managed Pressure Drilling (MPD) Constant bottom hole pressure (CBHP) technique to drill a challenging HPHT gas well successfully through an exploration field. The case study field elaborates challenges of uncertain formation pressure, narrow pore pressure-fracture pressure window and high background gas readings leading to extreme well complications. These challenges were counteracted with the implementation of Managed pressure drilling MPD technology, enabling to drill a well without any complications. To coupe with the complications including high temperature, narrow mud window & CO2 influx, MPD technology was called to be utilized in the challenging exploration field. With the implementation of MPD in this exploration drilling campaign, the case study well proved to optimize the overall drilling process, hence proving an answer to the previous problems in the field. The subject well was the first well to reach this depth. As a starting point, the actual bottom hole pressure limitations were established by performing MPD pore pressure tests, due to the lack of data as the only other option was to rely on geo-mechanics interpretations which is not very accurate, considering the case study specifically. Being it an exploration field, the bottom hole conditions were inconsistent and uncertain. The fully automatic MPD system enabled real-time evaluation and instant adjustment of the bottom-hole formation pressure changes, throughout the drilling process. The precise and instant control of bottom-hole pressure was the key factor of the overall success, hence mitigating any well complications, which previously costed weeks of rig days and associated oil based mud costs during losses. Since MPD technique evaluates & optimizes the required mud weight, hence saving the unnecessary overbalance on the well which had been the cause of several problems previously like losses, differential sticking and ballooning. Furthermore, for these critical narrow window wells, there was a need of a fool proof gain/loss monitoring system to stay top of the game all times. The sophisticated early kick/loss detection feature of the MPD system added value to the operation, which was independent of the conventional rig mud pit transfers and mixing which usually trigger false gain/loss alarms. The narrow drilling window was exacerbated by the increase in annulus frictional losses for these extended wells. The approach of ‘Prevention is always better than cure’ was adopted by the operator, since MPD prevents/mitigates a lot of hazards before they happen. This publication summarizes the details of how the MPD CBHP technique, early kick detection system & instant control system made it possible to efficiently and successfully execute the drilling process safely. It was proved that real time monitoring, and instant reactions are necessary to be able to adjust the BHP to keep the well under control throughout the drilling and post drilling operations like reaming trip in these types of high gas bearing formations. Hence MPD enabled the drilling of complex geological and weak fracture strength formations without any NPT for well control situations with the few value-added benefits like improved ROP, extending the total depth by 1300 ft additional to the initial plan achieving the deepest TVD (true vertical depth) drilled in the field.
Summary Knowledge of fracture‐entry pressures or formation‐face pressures (FFPs) during acid‐fracturing treatments in real‐time mode can help in evaluating the effectiveness of the treatment and improve the decision‐making process during execution. In this paper, methods and tools used to generate FFPs in real‐time mode with the help of bottomhole‐pressure (BHP) data are discussed in detail. The horizontal wells selected for the study were drilled and completed in the North Sea with permanent BHP gauges that enabled constant monitoring of downhole pressures. The tool in discussion uses the combination of treatment data such as surface pressure, fluid density, injection rates, fluid type, wellbore details, and wellbore deviation, along with bottomhole‐gauge pressures, to calculate fracture‐inlet pressures just outside the casing at active perforation(s) depth. The tool performs the calculations in “live” mode during treatment execution and simultaneously generates a dynamic array of data that assists in “on‐the‐fly” evaluation and the decision‐making process. Several acid‐fracture treatments were analyzed using the tool and led to important conclusions related to fracture‐propagation modes, acid‐exposure times, and the effectiveness of given acid types. The results had a direct influence on the modification of treatment designs and pump schedules to optimize treatment outcomes.
Abstract Objective Knowledge of fracture entry pressures or the formation face pressures during Acid Fracturing treatments can help in evaluating the effectiveness of the stimulation treatment in dynamic mode and can also enable and improve real-time decisions during the execution of treatment. In this paper, details of the methods and tools employed to generate formation face pressures in real-time mode with the help of live bottomhole pressure data, is discussed in detail. Methods, Procedures, Process The majority of the horizontal wells considered for this study were drilled and completed in the North Sea with permanent bottomhole pressure gauges that enabled constant monitoring of well pressures. The tool in discussion uses the combination of treatment data such as surface pressure, fluid density, injection rates, type of fluid, wellbore description, gauge depth, and wellbore deviation, along with bottomhole pressures to generate formation face pressures just outside the casing at active perforation depth. The tool carries out the calculations as the treatment is being pumped thus providing a dynamic array of several important parameters and can also evaluate the treatment after it has been executed. Results, Observations, Conclusions Acid fracturing treatments combine the basic principles of hydraulic fracturing and acid reaction kinetics to stimulate acid soluble formations. It is customary to start the treatment with a high viscosity pad to generate a fracture geometry and follow it up with acid to react with the walls of the fracture and etch it differentially. The non-uniform etching action of the acid creates an uneven surface on fracture walls that provides the requisite fracture conductivity which is key to enhancing the well performance. The effectiveness of a treatment schedule can be ascertained by determining and analyzing the pressure behavior during the injection process. Several acid fracture treatments were analyzed using the tool and led to important conclusions related to fracture propagation modes, acid exposure times and effectiveness of given acid types. The results had a direct influence on modification of treatment designs and pump schedules to optimize treatment outcomes. Novel Ideas The knowledge of formation face pressures is critical to the success of hydraulic fracturing treatments, especially in multi-stage and multiple perforation cluster type horizontal well completions. The tool developed in the study helps generate information that predicts pressures at fracture entry in real-time mode.
Abstract The pore and fracture pressure provides the boundaries during drilling operation. Nominal disparities between pore pressure and fracture pressure gradients cause the drilling window to be narrow, hence the term, “narrow margin wells.” Using conventional drilling methods, the drilling of narrow margin wells can be very challenging, hence the industry has begun exploring various methods of drilling through the narrow windows in a safe and effective manner. Managed Pressure Drilling MPD has evolved as a drilling method, which if properly engineered and implemented, could enable drilling through narrow margins in a safe and effective manner with significant reduction in drilling problems. MPD utilizes the application of Surface Back Pressure (SBP) in order to manipulate the bottomhole pressure (BHP) within the confines of the pore and fracture pressure and enables precise navigation while drilling through the narrow margins. According to Fredericks et al, the effective control provided by MPD allows a more precise and better management of the annular pressure profile, allows accurate management of bottomhole pressure while drilling, during connections and even during well control operations. The Weatherford MPD system was installed on an offshore Jack-Up rig to fulfill various requirements of the drilling operation. With the proven capability of the MPD system to “walk the line” between the pore and fracture pressure limits, the MPD system provided immense value to the entire drilling operation and enabled the operator to drill to the target depth. This paper will detail a case study of this MPD operation and also describe significant values provided by the MPD system to the overall drilling objective. The MPD system enabled early kick and loss detection, ability to maintain constant bottomhole pressure during drilling and during pumps - off events and ability to utilize the Annular Pressure Control mode (APC) to automatically displace heavy mud cap at specific depths in order to maintain the static overbalance when the drill string is out of hole. The MPD system was incorporated into the existing rig system with minimal disruptions to rig operations and equipment. Drilling process safety and operational efficiencies were greatly improved with the adoption of MPD.
Abstract Subsea pumping systems improve the safety and efficiency of drilling operations in tophole in water depths down to 525m (1720ft). The system collects mud at the seabed and pumps it back to the rig before the rig BOP / riser has been run. This equipment can be reconfigured to a 'pumped riser' mode for use after the riser is run. Drilling mud is pumped from an outlet in the marine riser with a blanket fluid, usually seawater above. Varying the level of heavy mud in the riser compensates for the Annular Pressure Loss. By dropping the level as mud circulation starts, there in no increase in the Bottom Hole Pressure (BHP). The Equivalent Circulating Density (ECD) is the same as the mud weight. There is a constant BHP when drilling, circulating, making connections, tripping, logging etc. The system is simple to understand and doers not rely on surface pressure or pressurising the marine riser. Connections are likely to be slower than the alternative methods but this is not considered a significant problem. In some ways is reassuring to be able to change conditions slowly and steadily. Pumped riser systems may also be used to drill surface holes, without any gas, at bottom hole pressures below seawater hydrostatic. This may be done to avoid losses into vugular formations or to improve drill rates in hard formations. Subsea pumping has also been used in a deepwater 5000ft (1500m) field trial. This proved up deepwater RMR but is a step towards the goal of full Dual Gradient Drilling in deep water. Managed Pressure Drilling (MPD) This is the agreed definition of MPD presented at the last conference "An adaptive drilling process used to precisely control the annular pressure profile throughout the wellbore. The objectives are to ascertain the downhole pressure environment limits and to manage the annular hydraulic pressure profile accordingly. The intention of MPD is to avoid continuous influx of formation fluids to the surface. Any influx incidental to the operation will be safely contained using an appropriate process."
Summary To meet the world's increasing demand for energy, petroleum-producing companies must search for oil and gas in increasingly hostile environments. One area showing great promise is in the deepwater areas of the US Gulf of Mexico. This is evidenced by increased lease sales and drilling activity that have occurred there within the recent years. As drilling moves into deeper waters, new technologies must be developed for safe and successful operations. Around 1996, four projects were initiated to develop dual-gradient drilling (DGD) technology for use in water depths greater than 5,000 ft. The four projects are Shell Oil Co.'s project (Gonzalez 2000), the SubSea MudLift Drilling Joint Industry Project (Smith 2000) (SMD), the Deep Vision project (Sjoberg 2000), and Maurer Technology's Hollow Glass Spheres project (Maurer 2000). Several publications have discussed the advantages that DGD technology has over conventional deepwater drilling in ultradeepwaters (Gault 1996; Schubert 1999; Smith et al. 1999). Although the advantages of the dual-gradient projects are well documented, there has been little published on one of the major concerns expressed by all four projects. That is, how does well control differ for Dual-Gradient Drilling as compared to conventional riser drilling (Schubert 1999; Juvkam-Wold and Schubert 2000; Weddle and Schubert 2000)? This paper reports on a comparison of the well-control aspects of DGD to those of conventional riser drilling. It is based on the work that the authors performed as part of the SMD project. Introduction DGD is an unconventional method of drilling in which a relatively small diameter return line is used to circulate drill fluids and cuttings from the sea floor to the rig's surface mud system (Fig. 1) (Schubert 2001). During DGD, the rig's marine riser is kept full of seawater. A rotating diverter, which is similar to a rotating control head, separates the wellbore and its contained fluids from the seawater in the marine riser. During wellkill operations, the return line is utilized as the choke line in conventional riser drilling.
This paper presents three modified calculation models for predicting swab pressure when the drillstring is pulled out of a horizontal well. They have been implemented in a computer program and the simulation runs have shown a good agreement of their predictions. The results have shown to be very dependable on the rheological model adopted for the calculations. Two rheological models have been investigated: Bingham and Power Law.
Also, the effects of some variables on swab pressure have been analyzed. The rheological properties of the drilling fluid, the drillstring speed and the length of the horizontal section have shown to have major effects on swab pressure calculations.
A more complex calculation procedure is also discussed in this paper. This procedure includes a transient flow model for a gas reservoir that allows to estimate the amount of gas entering the horizontal well when tripping out.
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Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and considered for publication in one of the two SPE magazines with the paper.
Field results indicate that displacing cement in turbulent flow during the primary cementing operation has materially reduced remedial cementing. Lower displacement rates with subsequently reduced frictional pressures have been achieved by using dispersants or thinners in the cement slurry. Failures caused by lost circulation and formation breakdown during primary cementing, sometimes encountered when high displacement rates are necessary for turbulent flow, have been substantially reduced.
The paper presents laboratory analyses of the effects of some dispersants on the rheological properties of cement slurries. These dispersants include (1) lignosulfonates; (2) phosphates; (3) alkyl-aryl sulfonates; (4) synthetic polymers. Such dispersants probably function somewhat like viscosity-reducing agents in muds, although the viscosity resulting from the gel structure of the hydration products apparently is reduced also.
Results on actual jobs using slurries containing thinners investigated are discussed. These results indicate that laboratory rheological measurements on slurries can be used successfully to predict pump rates necessary to achieve turbulency. Cementing operations using both low- and high-velocity displacement rates are compared.
High displacement rates required during casing cementing operations to improve mud displacement impose certain restrictions limiting use of this technique. Specifically, rheological properties of many commonly used cement systems preclude approaching turbulency in the annulus because the frictional pressures induced at the critical velocity approach or exceed the formation breakdown pressure.