Case Study 1

Case Study: Reducing Risk and Cost in Presalt Wells through Planning, Selection, and Application of Technology, Process, and Real-time Optimization

Ron Dirksen, Halliburton

Abstract

The successful completion of a well in the Brazilian presalt depends largely on how effectively one drills through the salt section. Drilling through salt means dealing with time-dependent borehole stability as well as tough and constantly varying drilling conditions. Drilling through and casing off the salt section before it becomes unstable helps reduce overall risk and drilling costs and is key to a successful operation in such conditions.

Careful analysis and planning, coupled with the selection and application of the most suitable drill bits and drilling tools, adherence to a best practices drilling process, and making use of real-time drilling dynamics data acquisition to apply to real-time drilling optimization has led to a significant reduction in drilling time, risk, and cost in this environment.

This paper presents a case study showing the analysis used, the planning process and results, drill bits and drilling tools modified and selected, best practices, and the drilling process and real-time optimization used to achieve impressive early results, which are continually being improved as more of these wells are drilled.

On the first two wells, the total time to drill through the salt was reduced by 50% from the historical average and is being improved with each new well drilled.

Drilling through the salt zone in the 17 1/2-in. section is challenging because of the long interval, approximately 1700 m. In the final third of this section sticking problems are commonly encountered, making it necessary to constantly ream to avoid becoming stuck.

The service company proposed using an a new bottomhole assembly (BHA) based on a point-the-bit rotary steerable system (RSS) configuration using a special bit stabilization capable of reaming the bottom section while drilling, saving reaming time and helping prevent sticking problems. The special stabilization reduced vibration levels compared to regular bit stabilizers offered the benefit of lower vibration and rate of penetration (ROP) increase. The optimized BHA and tool configuration combined with the planning and execution employed set a record for drilling through the salt section, resulting in significant cost savings.

Introduction

The service company had limited previous experience drilling through the thick salt sections overlaying the reservoir section in the presalt area of Brazil. On the few previous jobs, significant issues were experienced, resulting in the need for multiple bit runs, extensive reaming, and poor ROP in this section. This was primarily the result of not using the most ideal drill bits, drilling tools, and BHA design for drilling and keeping the borehole open in an efficient manner. The poor choice of drilling technology led to high vibration, poor ROP, and premature drill bit wear. The frequent trips and the long period of time the hole was kept open before being cased off led to salt creep as well as borehole washout and hole enlargement. This contributed further to poor drilling dynamics, frequent trips, and reaming necessary to keep the hole open.

Paper prepared for the 2013 Deep Offshore Technology International Ron Dirksen

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Fig. 1—

Offset well analysis of work performed since those previous jobs revealed that, at least some, improvement was possible with the selection of the proper drilling tools, drilling fluids, and drill bits, as well as through the use of real-time measurements to adjust drilling parameters and circulating practices.

The operator modeled several new bit and BHA combinations to address the issues and formulated a workflow to enable real-time optimization of the drilling process based on the use of real-time pressure, vibration, and weight-on-bit (WOB) measurements made while drilling.

The result was a substantial improvement compared to previous results, including those achieved by other service companies, significant improvement to well quality, and subsequent time and cost savings to the operator.

Planning

The following outlines the plan for drilling the 17 1/2-in. hole section.

Main Objective

The main objective of this operation was to drill the entire salt section (roughly 1780-m section length), in one bit run using a synthetic oil based drilling fluid (SBM).

The salt section consists of various layers of salt, mainly halite (NaCl), tachyhydrite (CaMg2Cl6·12H2O), carnalite (KMgCl3·6H2O), and anhydrite (CaSO4). The tachyhydrite and carnalite are particularly unstable, reactive, and prone to washing out, causing trouble with drillstring vibration and hole cleaning. The halite sections are prone to creep, causing borehole size reduction, equivalent circulating density (ECD) and drag increase, and (in extreme cases) borehole collapse, stuck, or severed pipe. All these phenomena are time-dependent and the sooner the hole is drilled and cased, the fewer the problems. This is achieved by selecting the proper drilling fluid to reduce the reactive aspects of the salt sections as much as possible. In addition, the proper drill bit, BHA, and hydraulics to maintain a high ROP, efficient hole cleaning, and little variation in ECD (avoiding pressure spikes and surges as much as possible) are key.


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Fig. 2—

Anhydrite is very dense and thus hard to drill with very slow drilling rates. The main anhydrite sections are at the bottom of the salt, directly above the reservoir. The right drill bit and drilling parameters are necessary to achieve as high of an ROP as possible. Bit wear and damage should be avoided and minimized as much as possible in the overlying section through maintaining the correct drilling parameters and avoiding harmful vibration and stick/slip, or whirl conditions.

To confirm the base of the interval and the bottom of the anhydrite section and drill a maximum of 15 m into the top of the reservoir below the salt, it is necessary to drill through the entire salt section so it can be completely cased off; however, minimum penetration into the underlying reservoir is desired as frequent loss of circulation is experienced in this area and to optimize production and hydrocarbon recovery.

Effective technology is necessary to detect the interface between the two sections, and such technology must be able to detect this interface as quickly as possible after the bit penetrates the reservoir section.

Common Problems with Offset Wells

Listed next are some common problems encountered when executing operations in offset wells.

• Very high levels of torque and vibration attributed to hole encroachment and enlargement. The salt section is also difficult to drill, with high torque and extensive incidences of bit stick/slip conditions.

• Difficulty determining the bottom of the salt and top of the reservoir. • Necessity of frequent and extensive reaming of the hole to maintain an open borehole and prevent stuck

pipe and loss of BHA.

Proposed Solution

The proposed solution for this operation was to address the torque and vibration issues and maintain verticality using a BHA, which included a modified RSS tool with a reaming stabilizer. The drill bit, BHA, drilling parameters, and


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drilling fluid were optimized to help ensure maximum ROP, reducing the time for hole problems to occur. Measurement while drilling (MWD) parameter measurement technology was included in the BHA to enable real-time monitoring and optimization.

The drill bit and reaming stabilizer helped ensure a full gauge hole was drilled, both when drilling straight and when steering the drill bit to correct the hole angle back to vertical (Fig. 3).

Fig. 3—

The RSS tool was set to maintain hole angle as closely as possible to 0° inclination. As a result, whenever the hole angle drifted more than 0.5° off vertical, the RSS system automatically corrected and steered the bit back to vertical by pointing the bit in the opposite direction of where it was heading at the time. With a relatively short gauge bit slightly tilted in the borehole, a possibility of drilling a slightly under-gauged hole existed; however, the reaming stabilizer directly above helps ensure the hole is full gauge. A full gauge hole is necessary to maintain smooth drilling conditions and effective energy transfer to the drill bit.

This configuration works well with point-the-bit RSS systems. Push-the-bit systems must exert significant side force to impact a change to hole angle and direction, with both a drill bit and reaming stabilizer present below the deflection device.

BHA and drill bit modeling are performed to help ensure the drill bit will drill effectively, both in straight drilling mode and while steering. The optimum drilling parameters for the drill bit for the different formations are determined from rock strength models, coupled with the drill-bit design for cutter layout and size. The BHA is analyzed for these optimum drilling parameters to determine side force on the reamer and on the rest of the BHA, as well as for potential harmful harmonics (Fig. 4).


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Fig. 4—Component data.

MWD drilling parameter measurement technology consists of a torsional efficiency monitor (TEM) in the RSS tool to help ensure efficient drilling and a dedicated sub containing sensors for weight, torque, and vibration (in this case, at the top of the BHA).

The TEM in the RSS tool measures accelerations in drive shaft rev/min and vibration. The shaft is directly connected to the drill bit and reamer. Thus, the measurement is directly related to drill-bit and reamer action. The measurements are processed in the RSS tool and made available to the operator at the surface in the form of a TEM value. Low TEM means low accelerations and vibration, hence, efficient drilling with low stick/slip and/or bit bounce.

The weight and torque sensors in the dedicated sub provide information to the surface about the actual WOB and torque being applied to the drill bit, rather than relying on surface measurements. This allows the driller to ensure the correct drilling parameters are being used for the bit to drill effectively. The three-axis vibration sensors are used to monitor drillstring vibration and, when detected, can be used to determine the nature of the vibration such that remedial action can be taken. All measurements, combined with surface measurements and observations, can provide an early indication of any hole problems that might be developing, such as poor hole cleaning, borehole constriction, and packoff.

Bit Design and Hydraulics

The initial bit selected to drill the interval was based on drill bits being used by others that had proven to perform adequately. After the initial runs, further refinement of the drill bit design was performed to realize higher ROPs as well as better flow and hole cleaning characteristics. Based on analysis of bit performance and further study of the


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formations being drilled, further drill bits were designed with a slightly deeper cut depth, and the forces across the cutters were balanced to help ensure the bit had a very low tendency to walk, or exhibit stick/slip behavior.

Optimization of the bit hydraulics was performed by changing the position, size, and direction of the nozzle ports to reduce washout problems and improve hole cleaning (Fig. 5).

The optimum drilling parameters for the bit (nozzle velocity, rev/min, WOB, and torque) were established and used as input parameters in the BHA, drillstring, and hydraulics modeling and optimization.

Fig. 5—Standard nozzles compared to optimized nozzles.

BHA Analysis and Optimization

The service company used proprietary software to analyze and optimize the BHA. A new model of the modified RSS with a reamer stabilizer and bit was necessary for accurate modeling.

Equilibrium rate, deflection, and bending forces were modeled and the BHA was tuned to deliver the objective performance.

In addition, critical rotary speeds, which could cause harmful harmonics in the BHA, were determined so these conditions could be avoided.

To pick the top of the reservoir, an at-bit-gamma-ray (ABG) measurement in the RSS tool located 1.9 m behind the bit was used.

One of the formation parameters that can be used to determine the transition from the anhydrite at the bottom of the salt section into the underlying reservoir is gamma-ray. Anhydrite has a very low content of radioactive material; whereas, the reservoir has a higher content of potassium and uranium, which will provide a higher natural gamma-ray reading. By using a gamma-ray sensor very close to the bottom of the BHA, the transition from the anhydrite into the reservoir can be detected and confirmed soon, reducing the chances of misinterpretation and running casing too early or too deep into the reservoir.


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Fig. 6—

Results

Application of the new RSS with reamer stabilizer, optimized BHA, and real-time drilling parameter management resulted in a significant reduction to drilling torque and vibration. Stick/slip of the drill bit and reamer stabilizer was minimal.

The TEM graph (Fig. 7) shows little stick/slip and torsional vibration of the RSS driveshaft after the initial period where the drilling parameters were tuned using real-time measurements feedback and optimization practices.


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Fig. 7—TEM real-time data.

All subsequent observed TEM levels were well below the empirically derived concern thresholds for this drilling tool. Good TEM levels translates into efficient drilling and high ROPs.

Accelerations along all three major axes were well below concern thresholds as well, meaning that lateral, axial, and torsional vibration in the drillstring and BHA was kept to a minimum. Again, this contributes to efficient drilling and minimal borehole damage from drillstring motion (Figs. 8 and 9).

Fig. 8—Memory data (average acceleration).


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Fig. 9—memory data (peak acceleration).

There was no evidence of borehole encroachment and packoff. ECDs were being maintained at a constant level and drillstring pickup and slackoff weights showed no evidence of excessive drag or friction. The difference between rotating and non-rotating pickup and slackoff hook loads were between 10 and 40 klb, with an average of ~20 klb in line with predictions from the torque and drag modeling performed in the planning phase (Fig. 10).

Fig. 10—


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The bottom of the salt section and top of the reservoir was determined as soon as possible after entering the reservoir section by the ABG tool, and 15 m of reservoir was drilled before pulling out of hole (POOH) and running casing (Fig. 11).

Fig. 11—

The previous average time to complete the 17 1/2-in. interval was 277 hr. The AFE was determined allowing for 369 hr. The actual time to complete the hole section was 118.5 hr, less than 50% of the previously realized average. Casing was run and cemented without problems (Figs. 12 and 13).

Fig. 12—


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Fig. 13—

Conclusions

• Careful analysis and application of effective modeling software enabled the selection of a better drilling assembly to reduce problems and improve performance.

• Real-time monitoring and management of drilling parameters results in better overall drilling efficiency. • A new BHA with an RSS and reaming stabilizer was effective for drilling a gauge hole through a salt section

in Brazil. The assembly reduced the torque and vibration observed with previous assemblies, resulting in smother, faster drilling and reducing time-dependent hole problems, such as hole enlargement and encroachment. Further refinement of the drill-bit design and drilling parameters should enable further improvements to the overall average ROP through the section.

• The ABG tool was effective for picking the top of reservoir early, allowing for the accurate setting of the casing with a minimal loss of production zone.

• Sustainable results are possible using this methodology in this region.

Case Study 1

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