Mud Design in HPHT

Copyright 2011, Society of Petroleum Engineers This paper was prepared for presentation at the Nigeria Annual International Conference and Exhibition held in Abuja, Nigeria, 30 July3 August 2011. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract The worlds energy demand is rising and favourable economics has allowed oil companies prospect and drill for oil in deeper, more challenging frontiers (which are prone to high pressures and high temperatures) than ever before. There are vast reserves of hydrocarbons in these remote locations that promise to bridge the gap between demand and supply for energy. However HPHT prospects can be a formidable challenge. The mud weight (which is higher for HPHT wells) must be accurately controlled because of the very narrow mud weight windows. This high mud weight requirement leads to problems of high solid loading and barite sag. Technology to effectively monitor downhole pressure and temperature conditions is not well developed. Rig crews need to be adequately trained to adopt best practices in HPHT drilling to minimize the risk of well control issues. In this study, the conventional practices and procedures in mud design were studied and analyzed. Advances in mud design were highlighted and case studies of some HPHT wells in regions around the world were reviewed to learn the lessons and best practices that led to their success. Many of the conventional practices were found to be inadequate for HPHT drilling. Rigorous

laboratory testing is necessary to generate detailed engineering guidelines for HPHT drilling fluids. Furthermore, a standard temperature concept used for controlling the surface mud weight was defined. The results of the new approaches to mud design and practices have been phenomenal. The importance of a stable mud system, detailed drilling program, best practices and correct field execution are fundamental. With the new approaches, many HPHT wells have been successfully completed in a cost effective manner and with no well control incidents recorded.

Introduction The aim of this study is to investigate the trend in mud design advancement as the search for oil takes us into even deeper frontiers. Drilling and producing petroleum from remote locations and at great depth has become increasingly attractive for several reasons1:

Abundant infrastructure in the way of platforms, producing facilities, and pipelines that would allow new production to flow quickly to market.

New technology such as 3D seismic and faster computers to locate potential formations.

The challenge facing the oil industry presently is that the process of economically extracting what remains of the worlds hydrocarbon reserves is stretching the traditional drilling and completion fluids to their performance limits and beyond. This is particularly true in the case of offshore and High Pressure High Temperature (HPHT) field developments where the application conditions are extremely challenging and the required fluid performance demands are exacting2.

SPE 150737

Advances in Mud Design and Challenges in HPHT Wells Woha Godwin (Jnr), Joel Ogbonna and Oriji Boniface; Institute of Petroleum Studies, University of Port Harcourt, Nigeria

2 Woha G. (Jnr) and Joel O.F. SPE 150737

A HPHT well has been defined by United Kingdom Continental Shelf Operations Notice as any well where the undisturbed bottom hole temperature is 300oF or greater and either the pore pressure exceeds 0.8 psi/ft or pressure control equipment greater than 10,000 psi rated working pressure is required. This study examines how conventional drilling and completion fluids have been failing to fully meet the demands of difficult HPHT well construction. It then charts the development of newer formulation as the new improved HPHT drilling and completion fluids. Fortunately, these improvements in techniques and better mud design have opened up possibilities that were previously very difficult to undertake.

Drilling Fluids The term drilling fluid refers to a liquid, gas, or gasified liquid circulating continuum substance used in the rotary drilling process to perform any or all of the various functions required in order to successfully drill a usable wellbore at the lowest overall well cost4. The objective of the drilling and completion process is to safely deliver high quality wells that are optimized in terms of providing shareholder value:

Best well productivity at lowest drawdown Best well integrity and longest structural

lifetime Lowest well construction cost Lowest environmental impact and liability

exposure Best reservoir information capture.

The choice of drilling and completion fluid used in a well construction operation has a critical influence on the extent to which an operator can meet this objective. In particular the fluids performance will play a significant part in determining whether or not an operator meets its key performance indicator targets in the following areas:

Time to drill and complete Well control and safety incidents Well integrity Well lifetime and maintenance costs Well productivity index Waste management costs Logging capability and interpretation Environmental footprint and impact Exposure to liability (short- and long-term)

The drilling fluid chosen for the upper well sections must offer a host of functionalities:

Ability to maintain the integrity of weak

rocks Ability to minimize fluid loss into

permeable rocks Ability to provide stable well control Ability to efficiently transfer hydraulic

power Ability to move cuttings to the surface Provide steel/steel and steel/rock lubricity Provide protection against all forms of

corrosion Allow formation evaluation Pose little or no hazard to rig personnel Have little or no adverse effect on the

environment Have little or no adverse effect on

elastomers If the drilling fluid is to be used in reservoir sections without further intervention, it must cause minimal change to the native permeability of the reservoir rock in the near wellbore area. The drilling fluid filtrate must also be compatible with other filtrates that might leak-off from subsequent cementing and completion operations. A completion fluid should have the same overall properties as a reservoir drilling-in fluid and, ideally, should be the same fluid minus any drilled solids. The limitations of conventional drilling fluids in HPHT drilling Conventional drilling fluids have inherent limitations in HPHT drilling conditions9. The high loading of barite in conventional muds creates high frictional pressure losses during circulation in long sections, leading to unacceptably high ECDs (Equivalent circulating densities) in narrow drilling windows2. High downhole temperatures can degrade the solids-carrying capacity of conventional muds, causing both dynamic and static barite sag and increasing the risk of loss of well control in high-angle wells. Oil-based muds can absorb large volumes of gas and this can cause well control problems too if the muds remain static for long periods in long horizontal holes9. To make things worse, an influx of hydrocarbon gas into oil-based mud may destabilize the formulation and cause barite sag. Pit gains may be more subtle as compared to

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3 Advances in Mud Design and Challenges in HPHT Wells SPE 150737

kicks in water-based mud and may take longer to manifest an observable gain, so extended flow checks (ten minutes or more) are advisable when using oil muds. This difference in response should be included in rig crew training when drilling deep gas wells1. Laboratory return permeability tests done on samples of a range of conventional mud types taken directly from the field show that they can cause considerable formation damage10, and the presence of very high levels of barite in high-weight muds formulated for high-pressure wells cannot improve matters. The use of Corrosion Resistant Alloys (CRA) in HPHT wells has been exposing fundamental flaws in the performance of conventional completion fluids based on chloride and bromide brines2. It is well-documented that severe localized corrosion and stress corrosion cracking of CRA tubulars will take place in HPHT wells if they are exposed to chloride and bromide brines containing oxygen, carbon dioxide or hydrogen sulphide11-17.

Furthermore, the sulfur-containing corrosion inhibitors commonly used in halide brines are known to decompose to H2S at high temperatures and create another source of stress corrosion cracking18. To date the vendors of halide brines seem to have made little progress towards finding an effective inhibitor to mitigate the serious corrosion problems created by their products in HPHT wells.

In conclusion2, a review of the challenge posed to conventional fluids by the demands of HPHT operations indicates that the use of hydrocarbons, solid weighting agents and halide brines (chloride and bromides) in drilling muds and completion fluids increases the risk of problems with well control, well integrity and well productivity. The negative influence of conventional fluids on drilling and completion operations can be sufficiently serious to compromise safety and degrade the economics of difficult or ambitious HPHT field developments2. Formulations Commonly Used in HPHT Drilling Invert emulsion fluids have been utilized for drilling HP/HT wells and the technology is adequate for temperatures up to 500oF, but recent HPHT activity presents even harsher environments with estimated Bottom Hole Temperature (BHT) approaching 600oF1. It is a common occurrence to have hole washouts while drilling with water-based mud19. There are

several reasons for this and until a concerted effort is taken to address the issue, such holes are bound to develop. Some of the problems that large washed-out holes cause are poor hole cleaning while drilling the hole, increased chances of stuck pipe, poor wireline log quality, bad zonal isolation after cementing primary casing strings, and loss of production due to inadequate zonal isolation19.

Drilling HPHT Infill Well in a Highly Depleted Reservoir Drilling infill wells on HPHT fields after a significant depletion has occurred represents a real challenge. It requires drilling from a cap rock remaining at or close to virgin pressure into a reservoir in which pore and fracture pressures have largely decreased due to production. No mud-weight-window exists anymore at the transition between cap rock and reservoir20. The difficulty is further increased by uncertainties in the pressure profile along the well path, the rock mechanics and their change generated by the high and rapid depletion, and also by depth uncertainty on the top reservoir20. For this reason, most HPHT fields are developed by drilling all wells before a pre-defined limit of depletion level is reached at which the mud-weight-window closes20. This limit is usually low. However, HPHT producer wells face depletion related threats to their integrity: sand production and / or deformation of the production liner under rock movement. When these threats become effective, the well and its associated production will be lost. Replacement wells will need to be drilled. Additional wells are also needed to increase reserves by creating new off-take points20. All these challenges were tackled with a good degree of success by a recent depleted reservoir HPHT campaign (TOTALs ELGIN/FRANKLIN in the North Sea). The success of this first HPHT infill well after significant depletion proved the feasibility of drilling such wells. It opened the door to new opportunities in HPHT developments.

Advances in mud design A review of the literature1-22 showed that for non HPHT wells, the effects of pressure and temperature on mud weight can be ignored. However, for HPHT wells, the effects of pressure and temperature on surface mud weight, the equivalent downhole mud weight, and the

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equivalent circulating density (ECD) must be taken into consideration23. It would be easier to define and manage if a constant bottom hole pressure can be maintained during drilling operations. Unfortunately, due to the changes of downhole mud temperature profile and the effect of temperature profile on equivalent mud weight, it is impossible even to maintain a constant hydrostatic pressure for a given well operation23. The hydrostatic overbalance always varies within a certain range, depending on the pump rate and the mud properties. Although the circulating mud temperature profile is constantly changing, the geothermal temperature profile can be assumed to remain in a constant state. Therefore a constant hydrostatic overbalance can be designed and maintained under geothermal temperature profile. Using this concept, new procedures have been developed to achieve this23. The circulating temperature profiles at different operating conditions are then established, and the hydrostatic overbalances are calculated to ensure that a minimum acceptable overbalance is maintained during different operations. Listed below is the review of some selected advances made during some HPHT drilling campaigns.

Bottom-Hole Mud Pressure and PVT The main objective of any hydraulics design, along with optimization of drilling efficiency, is to minimize the risk of a well control incident. Gao et al (1998) defined bottom-hole mud pressure Pmud, as a general term for mud hydraulics with the following equation. !!"# ! !!"#"$% ! !!!"#$%&' ! !!!"##$%&'!(1) In the above equation Pstatic is the hydrostatic mud pressure, which may vary depending on the downhole temperature profile. The "Pdynamic is the dynamic mud pressure(s) which is defined as mud pressure variation caused by any disturbance to the mud in the hole. The "Pdynamic can be positive or negative depending on the direction of the operation. The dynamic mud pressure(s) can be a single pressure or combination of different dynamic pressures such as surge and swab pressure, inertial pressure due to string acceleration or deceleration and pressure required to break gels. The "Pcuttings is the equivalent mud weight increase due to cuttings loading in the annulus, which is dependent on the pump rate, rate of penetration, well geometry, mud properties and cuttings size.

Using the above equation, the bottom-hole mud pressure is generalised23, enabling different components of the pressures to be analyzed in isolation depending on the operation. Thereafter, the operating margin and operational guidelines can be derived. The limitations in HPHT drilling can be so severe that MWD/LWD tools become unusable, rendering down-hole annular pressure measurements used for pressure management, unavailable. We can only rely on the drilling fluid and temperature/hydraulic models as our best or only source of down-hole pressure information1. Although the hydrostatic pressure !!"#"$% is constantly changing, it has been realized that one of the few constant parameters in the well bore is the geothermal temperature profile23. If the hydrostatic pressure is calculated based on the geothermal temperature gradient, a constant hydrostatic pressure can be obtained for a given surface mud weight. Obviously, the hydrostatic overbalance would vary during circulation. But, as soon as circulation is stopped, the hydrostatic overbalance will change towards the overbalance under geothermal temperature gradient. To ensure that an adequate hydrostatic overbalance is maintained immediately after stopping circulation, circulating temperature profiles are established and used to calculate the hydrostatic pressure !!"#"$%.

23 Ron et al (2006) carried out a series of studies on temperature modeling, equivalent static density prediction (ESD) and a new viscometer. He illustrated isobaric PVT results on a commonly used base-fluid. This illustration showed that HPHT and deepwater wells required adjustments for the temperature and pressure driven compression and expansion characteristics of the whole drilling fluid. This is shown in Figure 1. As shown in the Figure, according to Ron (2006), laboratory measured data to 30,000 psi are represented by the blue circles; a third-degree polynomial (blue line) provides a good fit for these measurements. Using a third-degree polynomial based on historically available # 20,000 psi data and extrapolating to 30,000 psi (red curve) will substantially overestimate the degree of compression, introducing significant errors in down-hole pressure calculations. This example highlights the necessity for measured data reflecting down-hole conditions1. In drilling, PVT information is used to achieve an accurate pressure profile of the well due to hydrostatic pressure from the drilling fluid. Whole mud density under downhole conditions can be


precisely predicted if the PVT data on the base fluid and brine phases used in the composition of the whole mud is available. A retort analysis from the rig site can be used to determine the volume fractions of base fluid, brine and solids of the whole mud. The volume fractions of each component are then used in a compositional model to determine the change in density due to pressure and temperature. Peters et al. (1990) presented a compositional model in 1988 which considers each component in expressing the density of a whole fluid as a function of pressure and temperature:

!!!!!!= !!!!!!!!!!!!!!!!!!!!

!!!!!!! !!"!! !!!

!! !!"!!!!!(2)

Performing the density correction every 100 feet of vertical depth has proven to be an acceptable method for Equivalent Static Density (ESD) prediction. Figure 2 shows a corrected pressure profile, expressed as ESD in pounds per gallon, due to compressible fluid components and an uncorrected pressure profile. This example is an 18.21 lb/gal, 89:11 oil/water ratio (OWR) invert emulsion drilling fluid.

Viscometer With the depth horizons of HP/HT drilling expanding, a technology gap was recognized in the measurement of fluid viscosity at down-hole conditions. Historical viscometer technology is limited to measurements at # 500F/20,000 psig. Some completed and on-going HPHT wells have bottom-hole conditions approaching 600F and 40,000 psig. Since this was identified as a major technology gap and fluid behavior had never been evaluated at these extreme conditions, Ron Bland et al (2006) set out to develop a new viscometer suitable for HP/HT drilling. Criteria for the new HP/HT viscometer included:

Working pressure up to 40,000 psig Working temperature up to 600F

Ron et al succeeded in designing and fabricating a new HPHT viscometer capable of testing fluids used for deep gas drilling and this was made available to the industry. The new viscometer, the Chandler 7600, has met the design criteria 40,000 psig/600F and is capable of accurate measurements in fluids containing ferromagnetic material.

An Accurate Hydraulics Program For a given oil/water ratio in an invert emulsion mud, the hydraulics program used in the HPHT sections can generate the following information in addition to normal hydraulics information such as pump pressure and bit hydraulics:

Hydrostatic pressure Pstatic at a given downhole temperature profile.

The dynamic pressure(s) as described in Eq. 1, including an individual dynamic pressure or any combination of the dynamic pressures such as surge and swab, pressure required to break gels and inertial pressure.

Surface mud weight versus temperature chart.

Thermal expansion of mud in the hole. Effects of the various parameters on

bottom hole mud pressure or ECD.

A Temperature Simulator

The mud temperature profile in a wellbore changes depending on the drilling parameters and circulating history. The changing temperature profile leads to varied mud hydrostatic pressures Pstatic. Therefore, a temperature simulator is required to establish the temperature profiles at different pump rates and times from initiation of circulation. The information generated from the temperature simulator is then used by the hydraulics program to predict the Pstatic element at circulating temperature profiles. The purpose of this is to ensure that a certain hydrostatic overbalance is maintained at different pump rates to keep the well under control immediately after stopping circulation. This also helps to analyze the ECD more accurately.

The temperature simulator used generates the following temperature profiles for both steady state and transit conditions:

Mud temperature profile in the annulus

Mud temperature profile inside the drill string

Time dependency of the temperature profiles

From a safety aspect the FLT (Flow Line Temperature) needs to remain within the temperature limits of the blow out preventer (BOP)1: usually below 200F. From a cost


perspective the BHCT is important with regards to the downhole tools used for formation evaluation and geosteering; usually limited to about 350F before heat damage occurs1. Either or both of these scenarios could be addressed by the use of mud coolers to reduce circulating temperatures. The effects of insulated drill pipe and risers, multiple lithologies with variable thermophysical properties and cooling effects from surface area of the active mud system should not be ignored as they act like mud coolers1. Ron (2006) showed the results of modeling with and without mud coolers on an HPHT well1. A typical plot of the established temperature profile is shown in Fig. 3.

It can be seen from Figure 3, that when the mud is in circulation, the temperature increases at shallow depth and the temperature decreases at deeper depth. As a rule of thumb, in about 2/3 of the wellbore from the top down, the mud temperature will be increased and in about 1/3 of the wellbore, the mud temperature will be decreased. As the mud temperature increases, the mud weight wiII be reduced and vice versa.

Therefore, comparing with the hydrostatic mud pressure under geothermal temperature gradient, the Pstatic element in the total mud pressure Pmud will be reduced under circulating temperature profiles.23

The Use of Cesium Formate Brines Experience shows that conventional drilling and completion fluids have been failing to fully meet the demands of difficult HPHT well construction2. Cesium Formate brines, originally developed from Shell research in 1986 and improved with time have been touted as the new improved HPHT drilling and completion fluids2. They have been widely used in the North Sea and the Gulf of Mexico. The limitations of conventional muds were discussed extensively in the literature review. Problems of high barite loading and its effect on ECD, barite sag caused by high temperature and oil muds absorbing high quantities of gas are paramount. Shell, in the early-1990s, began research to meet these challenges. They developed an aqueous formulation of solids-free, non-corrosive brine with densities up to SG 1.57 (13.1 ppg) that had viscosity and fluid loss control stability at high temperatures. They further realized that with cesium formates, the density could be extended2 to SG 2.30.

At the closing stages of the first phase of product development in 1995 the perceived advantages of the formate brines when compared with conventional HPHT drilling and completion fluids were2:

Minimal formation damage Maintenance of additive properties at high

temperatures Elimination of barite and its sagging

problems Reduced hydraulic flow resistance Lower ECDs Lower swab and surge pressures Better power transmission to motors and

bits Low gas solvency Better kick detection and well control Faster flow-checks Low potential for differential sticking Naturally lubricating Reduced torque and drag Inhibition of hydrate formation Non-hazardous Very low corrosion rates, local and general No stress corrosion cracking Compatibility with elastomers Biodegradable and posing little risk to the

environment The advent of fluids with such a unique set of performance advantages promised to eliminate a host of HPHT well construction problems caused by the inherent deficiencies of traditional drilling muds and brines2. In 1996 Mobil conducted the first field trial of a formate-based drilling fluid in a high temperature well24. Over the next 3 years Mobil used potassium formate brine as a drill-in fluid in a further 15 deep gas wells in Northern Germany. The performance of these fluids was reviewed in 200024. Mobil concluded:

Formate-based fluids have been applied as high density, temperature stable, low solids, environmentally friendly, non-damaging, non-corrosive drilling and reservoir drilling fluids.

The use of formate-based fluids has resulted in a dramatic increase in drilling performance and hydraulics.

Since the use of formate-based fluids has been implemented, the productivity of wells has increased compared to wells drilled with conventional muds.

Stuck-pipe incidents have been significantly reduced with formate-based fluids due to thinner filter cakes and the


naturally low friction coefficient of formates.

Despite exposure to temperatures of up to 165C (329F) BHST (Bottom hole static Temperature) the polymers in the formate brine have retained their stability.

Corrosion has been minimal to negligible. A decade later potassium formate brines are continuing to provide the solution to the challenges posed by drilling deep high-angle gas wells. In SPE paper 92407 and accompanying texts25,26, Saudi Aramco have described how they have successfully used fluids based on potassium formate brine to drill and complete a series of long horizontal wells at 13,900 ft to 14,600ft TVD in hard and abrasive sandstone. Aramco reported that one of the first wells drilled with a low-solids SG 1.44 (12.0 ppg) formate fluid exhibited greatly improved drill string/wellbore lubricity and bit performance, reduced torque and drag, reduced ECDs and lower pump pressures. Since entering service in 1999 cesium formate brines have been used in 101 individual HPHT operations in 21 different fields. In this time they have passed extensive and rigorous field-testing2:

At densities up to SG 2.25 ( 18.7 ppg) At temperatures up to 215oC (420oF) For periods up to 18 months downhole In hole-angles from near-vertical through

to horizontal In oil, gas and condensate reservoirs (all

sandstone) with permeabilities from < 1mD to 2 Darcy

In the Kristin field, which is the most extreme HPHT field in Norway with a reservoir pressure of 911 bar and a temperature of 175oC, the well R-3 H was drilled with an inclination of 75o without any well control incidents and 2 days ahead of schedule27. Thus Kristin introduced a new term in the Oil and Gas industry: HAHPHT, High angle High Pressure High Temperature wells27. The first two of four high angle wells were drilled using cesium formate brines because of the lower ECD and higher operational margin that it confers on the narrow mud weight window. However its use had to be discontinued after the first two wells because extensive fluid loss was reported of the magnitude of 10 times higher than with conventional oil based mud27. With this type of drilling fluid total loss of circulation was experienced in the reservoir. Cesium formate mud was also reported to be very expensive. After the experiences with Cesium formate mud system it became apparent that drilling high angle

well would not be possible with this type of drilling fluid. So for the high angle wells an oil based mud system was chosen27. The big challenge with a conventional oil based mud system is weight particles in mud weights above 2.0 sg. Barite is used as weight particles. It is very difficult to avoid any sagging of barite with so much weight particles in the mud system, especially if the well is left without circulation for days. Experience from Kristin27 shows reduction from an original mud weight of 2.05 sg down to 1.80 sg.

Review of some Published case studies

HPHT drilling of four wells in HERON field, UKCS central Graben23 The Heron field is located in Central Graben, block 22/30a in the UK sector of Central North Sea. Its main reservoir is the Upper and Lower Skagerrak. The well information is summarised below:

Measured Depth (MD)/True Vertical Depth (TVD) = 15613 /15279 ft

Maximum pore pressure gradient at 13873 ft TVD = 12494 psi (Temp=314oF)

Maximum bottom hole static temperature [BHST) = 343oF

Base fluid % by volume = 48, water % by volume = 13

Sea Level = 90 ft Water depth=301 ft Atmospheric temperature = 60oF (from

surface to sea level) Seawater temperature = 40oF

Before drilling the HPHT hole sections, extensive hydraulics design work was carried out and the following design procedures were developed and used:

1. Gather well data including formation tops (prognoses and possible shallow depths), pore pressure, fracture pressure and geothermal temperature profile.

2. Define the acceptable minimum hydrostatic overbalance over the expected maximum pressure gradient: For this HPHT section, about 200psi overbalance over the maximum expected pore pressure gradient was considered as the minimum acceptable level. Therefore, the required equivalent downhole mud weight at top of the reservoir under geothermal temperature gradient was set to be 915 pptf (psi/1000 ft)

3. Determine the required surface mud weight


4. Determine the standard temperature for surface mud weight based on the geothermal temperature gradient: This was the most important parameter in the new process. It was assumed, based on offset data, that the geothermal temperature gradient from the drill floor to the top of the reservoir i.e. maximum expected pore pressure gradient at 13,8731 ft TVD is 2.7oF per 100ft TVD. Drill floor temperature is 60oF. With this geothermal temperature gradient, the hydraulics program calculated that if the surface mud weight was measured at 120oF, the surface mud weight would be exactly the same as the equivalent downhole mud weight. Therefore 120oF was defined as the standard mud temperature for surface mud weight control. The required surface mud weight was defined as 915 pptf at 120oF. As the flowline temperature deviates, the surface mud weight is allowed to increase or decrease accordingly.

5. Establish the circulating mud temperature profiles at different pump rates and time intervals.

6. Calculate the equivalent downhole mud weights at the established temperature profiles to ensure that hydrostatic overbalance is maintained immediately after stopping circulation. If necessary, increase the hydrostatic overbalance and repeat the above process until meeting all the criteria: Under geothermal gradient, the hydrostatic overbalance at the maximum pore pressure gradient or top of reservoir was designed to be 200 psi. Since Pstatic tends to decrease when the temperature profile is changed from geothermal gradient to circulating condition and the circulating temperature profile is pump rate dependent, the hydrostatic overbalances at different pump rates must be analyzed to ensure that a certain hydrostatic overbalance can be maintained immediately after stopping circulation23. It was established that if 915 pptf surface mud weight is maintained at 120oF, the equivalent downhole mud weight or Pstatic at different pump rates will be about 910 pptf at different pump rates and the EMW under geothermal gradient is 915 pptf at depth 13873 ft TVD. This provides adequate hydrostatic overbalance

(200psi) during static condition and 131 psi minimum when immediately stopping circulation. It was thus recommended that the surface mud weight be maintained at 915 pptf at 120oF.

As flowline temperature changes, define how the surface mud weight should be maintained: obviously, the surface mud temperature will vary depending on the flowrates and other drilling parameters. The surface mud weight will then change with this changing temperature. Once the oil/water ratio of the mud is given, the hydraulics program can be use to produce a surface mud weight versus temperature chart as shown in figure 4. The chart shows that to maintain a constant hydrostatic overbalance in the geothermal temperature gradient, the surface mud weight must be controlled based on the return mud temperature. When the surface temperature increases, the surface mud weight wiII be allowed to reduce due to thermal expansion and vice versa. For example, the surface mud weight will be allowed to decrease from 930 pptf to 906 pptf when the return temperature is increased from 70o

to 150F. The effect is very significant.

7. Establish the ECD and design the maximum applicable pump rate.

8. Analyze the tripping speeds based on surge and swab pressures: Given the bottom hole assembly (BHA), the ECD, surge and swab pressures to ensure safe operation can be determined.

Defining the standard mud temperature is a major difficulty with this approach23. The rule for the standard temperature is that if the surface mud weight is measured at the standard temperature, the equivalent downhole mud weight under geothermal temperature gradient will be exactly the same as the surface mud weight23.

The Procedure to Measure Surface Mud Weight It has already been shown that the conventional procedure to measure the mud weight could lead to significant errors. A new procedure to measure the mud weight was applied. It involves measuring surface mud weight and reporting it against a temperature23.


Conventional Procedure of Measuring Mud Weight Conventionally, the following procedure is used when measuring flowline/active pit mud weight:

Take a sample from the flowline or active pit

Measure the Marsh Funnel viscosity Measure the mud temperature (after the

mud passes through the Marsh Funnel ) Measure the mud weight Record the mud weight and the

temperature. Some engineers measure the mud temperature directly from the flowline. Surface mud weight was not correlated against the temperature and the mud weight was always kept as a constant no matter the mud temperatures. The above procedure was monitored and the results showed that the measured mud temperature with such a procedure was 5oF to 15oF different from the mud temperature inside the mud balance at the time of measuring the mud weight. Consequently, about 1.5 to 4.5 pptf error in the mud weight results. This is both risky and easily preventable. A new procedure was developed for measuring the surface mud weight so that it can be correlated with temperature.

New Procedure for Measuring Surface Mud Weight From the effect of temperature on surface mud weight, it is clear that surface mud weight will be increased from 906 pptf to 930 pptf if the mud temperature is decreased from 150oF to 70oF. On average, for an oil to water ratio of 80/20 and 915 pptf fluid, the mud weight decreases by +/-3 pptf with each increase of 10oF in temperature. The differences in surface mud weight will directly affect the equivalent mud weight under downhole conditions, which is very significant considering the small hydrostatic overbalance of 200 psi for typical HPHT sections. Therefore, accurate measurement of the surface mud weight and the corresponding temperature becomes important23. Due to the inaccuracy in the traditional way of measuring flowline temperature and mud weight, a new procedure was developed and implemented for the HPHT sections of the wells in the Heron field, the procedure is as follows:

Take a sample from the flowline or active pit

Measure the viscosity (Marsh Funnel) Flush the mud balance twice with the mud

sample Fill up the mud balance Measure the mud temperature inside the

mud balance Measure the mud weight Record the temperature and mud weight Measure and record the flowline

temperature

With the above procedure, the flowline temperature and the mud temperature at which the surface mud weight is measured are different. Flowline temperature will be used to calculate the equivalent mud weight during circulating conditions and the temperature at which the flowline mud weight is measured will be used as a baseline for surface mud weight control. It is pertinent to note that maintaining a constant surface mud weight is not practical as the mud weight tends to increase due to water evaporation and accumulation of fine drill solids. Therefore, the surface mud weight was allowed to fluctuate within a 5 pptf (0.01 S.G.) band. That is to say, for the given wells, the surface mud weight was allowed to change from 915 to 920 pptf at 120oF. However, the aim was to maintain the value at 915 pptf and every attempt was made in this regard. The surface mud weight versus temperature chart was updated on a regular basis to correct for any changes in oil/water ratio. This procedure was proved to be successful.

Kill Mud Weight Calculation In case of a well control situation, a kill mud is required. The kill mud weight can be calculated based on the shut-in-standpipe pressure. However, the kill mud weight should be fine-tuned based on the mud weight at the standard temperature. For example, if the shut-in-pipe pressure is reported to be 450 psi with a standard mud weight of 915 pptf at 120oF and the TVD depth is 15,000 ft, the kill mud weight can be calculated to be 915+ (1000 * 450/ 15,000) = 945 pptf at 120oF. When the kill mud is mixed, the surface kill mud weight should be controlled based on the mud weight versus temperature chart shown in Figure 5. From the chart, if the mud temperature in the kill mud pit is 100oF, the surface kill mud weight should be set at 951 pptf instead of 945 pptf considering the effect of temperature on surface


mud weight. Obviously, if 945 pptf kill mud is mixed in the pit, the well cannot be killed. This procedure was not applied however, as no well control incidents occurred during the project23.

Field Results No drilling related problems occurred during the four HPHT sections. 20 days were allocated in the drilling plan to drill the HPHT section of the well, this section was completed in only 10 days. About 10 rig days were saved for the HPHT section alone as no well control incidents occurred23. In other HPHT wells, well control incidents occurred once or twice per well on average. The improved performance was attributed, at least in part, to the new procedures and mud design. To further illustrate this point, maximum flowline temperature reached 150oF during the HPHT sections, if conventional procedures had been followed, the mud weight would have maintained at 915 pptf at (the elevated temperatures. This is equivalent to a9.0 pptf increase in mud weight. This is significant enough to fracture the formation23.

HPHT drilling in the Shearwater Field, North Sea, UK The Shearwater project is located in Block 22/30b of the UKCS with a reservoir pressure in excess of 15,000 psi and a maximum temperature of 380oF. The principal factor making this project most challenging is the extremely narrow drilling windows, in the worst case less than 480 psi, which is the difference between the pore and fracture pressures28. This was reported to be much narrower than in other HPHT projects in the North Sea. Erhu (2000) discussed the technical issues including the mud design that contributed to the success of the project. They include:

Mud system and formulation Criteria for the optimum level of treatments

with emulsifier and oil wetting agent Specification of critical mud properties Management of bottom-hole pressure Hydraulics program versus downhole

pressure tool HPHT procedures Operational practices

At this point, this study shall review the specification of critical mud properties and the HPHT procedures that guaranteed the success of the shearwater campaign.

Specification of Critical Mud Properties In the HPHT sections, four mud properties, including mud weight, S/W ratio, rheology and HPHT fluid loss were defined as critical, which were tightly controlled and maintained to optimize the drilling operation28.

Mud weight The same new approach to the mud weight as applied in the Heron fields and reported by Erhu (1998) was applied in the Shearwater project. A standard temperature was defined and used to correlate the surface mud weight with the equivalent downhole mud weight. Surface mud weight was then controlled by a temperature versus mud weight chart28. The surface mud weight was allowed to increase with decreasing flowline temperature and it was also allowed to decrease with increasing flowline temperature so that a constant bottomhole pressure can be maintained.

S/W ratio An increase in the brine phase or a reduction in S/W (Synthetic/Water) ratio will significantly increase the viscosity of the mud system, which will reduce the requirement on viscosifier. The traditional argument for low S/W ratio muds is that the dispersed brine phase will increase the suspension capacity due to the effect of hindered settling, which minimizes barite sag28. However, with low S/W ratio, less viscosifier will be required, which will reduce the formation of the gelling structure. In theory, therefore, there should be an optimum S/W ratio, at which the optimum combination between the gelling structure for suspension from viscosifier and the dispersed brine droplets for hindered settling can be achieved to minimize barite sag. Erhu (2000) reported that the optimum S/W ratio for this project at which minimum tendency for barite sag exists was found to be 80:20. During drilling operations the S/W ratio was maintained in the range from 79:21 to 83:17 in the HPHT sections. The S/W ratio was maintained in the specification throughout the drilling phase, with an effort of keeping the S/W ratio as close to 80:20 as possible28.

Mud Rheology Traditionally, PV (plastic viscosity) and YP (yield point) were used to define the specification of mud


rheology. These two parameters were used to optimize mud formulations with the aim of achieving as low a PV as possible. This worked well in most wells due to the large tolerable errors. However, for HPHT wells, this has significantly increased the drilling problems such as lost circulation, surging/swabbing and kicks25. The perception in the industry was that the higher the PV, the higher the ECD25. Therefore, every effort was made to minimize the PV in the optimization of mud formulations. In a 1998 paper, Fennel and Gao29 argued that the PV and YP were not relevant to the ECD as they were derived from the 600-rpm and 300-rpm readings of the Fann viscometer. However, during a typical drilling operation, the shear rate in the annulus is usually in the range of 80 to 100 rpm equivalent. As a matter of fact, it has been demonstrated that mud with a lower PV can result in a higher ECD than mud with a higher PV25. The PV and YP correlate to the shear rate range inside the drillstring, where the majority of the pump capacity is consumed. If there is a limited pump capacity, the PV should be controlled as low as practically possible. However, for HPHT wells, the main concern is the pressure loss in the annulus or ECD rather than the pump capacity. Therefore, the 100-rpm reading should be controlled to minimize the ECD. In the Shearwater project, the 100-rpm reading was defined in the range of 35 to 42. A reading of 35 was defined as the minimum rheology as a further reduction would cause barite sag and the reading of 42 was defined as the maximum rheology based on extensive simulations on the ECD25. Mud was formulated and maintained with optimum 100-rpm reading instead of the lowest PV. During normal drilling, an attempt was made to maintain the rheology at the lower specification. Before pulling out of hole for tripping, logging or running casing, simulations with hydraulics program were made to determine the maximum tolerable rheology for surging and swabbing. The mud was then treated to achieve the maximum tolerable rheology prior to pulling out of hole to minimize sag.

HPHT fluid loss In the reservoir sections, the HPHT fluid loss was programmed to be less than 5 cc at the maximum geothermal temperature from 360oF to 380oF and in practice it was maintained below 3 cc to minimize the risk of differential sticking in the deeper section of the reservoir.

HPHT Procedures Operational practices were also developed and used to achieve the outstanding drilling performance in the Shearwater project.

Calibration of mud balance To maintain an accurate mud weight, the mud balance must be properly calibrated. The balance should be calibrated with cesium formate heavy brine at a density close to that of the active mud system28. The brine density should be measured with two different hydrometers to ensure their accuracy. In one of the HPHT sections, it was found that an inaccurate reading from the hydrometer led to a lighter mud being used in the hole and this resulted in a loss of 24 hours rig time28. However, it could have led to a kick if it had not been picked up from the PWD tools. To ensure the accuracy of the mud balance, a procedure has been developed for its calibration.

Pilot testing HPHT muds are very sensitive to treatments. Pilot tests must be carried out before adding any chemicals into the active system. Furthermore, the mud should be pilot tested on a continuous basis to ensure that any depletion of additives is compensated for, particularly for the emulsifier and oil wetting agent. The effects of emulsifier and oil wetting agent concentrations on the PV were monitored on a regular basis to identify their depletion and any necessary treatments were made before the mud properties are deteriorated28.

Mud sampling and testing To ensure the mud stability in the reservoir sections, a Fann 70 rheometer was used to measure the mud rheology under downhole pressures and temperatures by sending mud samples onshore28. Static barite sag was also measured on a regular basis. Any signs of increasing sag tendency could be identified and rectified by chemical treatment.

HPHT training Due to the complexity and potential risks, training is necessary. The objective of the training was to make sure that all rig personnel were made aware how their operations might affect the well and how to react in case of an unexpected incident28.


Continuity of personnel Mud engineers are part of the integrated part of the rig team. In addition to mud treatments, the mud engineers must work closely with the drilling supervisor, the rig crew and other third parties. To ensure that the operation can be run smoothly on a continuous basis and lessons learnt can be captured and carried from well to well, no changes of the mud engineers should be allowed throughout the project period and especially during the HPHT sections28. The above strategy proved to be a success in Shearwater and is strongly recommended on future multi-well HPHT projects.

Field Results Application of the new procedures from mud formulation to best operational practices has proved to be a great success. The Shearwater project has set new standards for the drilling of HPHT wells. The Shearwater project has outperformed the best in class HPHT wells by about 60 days from handover to production. It is also on record that of the North Sea HPHT wells, that four out of the five best performing wells were delivered by the Shearwater project28. In total, the six-well HPHT project was 230 days ahead of schedule and $48 million below budget.

Conclusions Recent developments and advances have contributed to the successful drilling of many HPHT wells. The importance of a stable mud system, detailed drilling program, best practices and correct field execution are fundamental. The following main conclusions and recommendations about fluid engineering and management in HPHT wells have been drawn.

1. Rigorous laboratory testing is necessary to generate detailed engineering guidelines for HPHT drilling fluids. PVT information of the base fluids is used to achieve an accurate pressure profile of the well due to hydrostatic pressure from the drilling fluid.

2. A compositional model to determine the change in density due to pressure and temperature has been presented. Each component is considered in expressing the density of a whole fluid as a function of pressure and temperature. Performing the density correction every 100 feet of vertical depth has proven to be an acceptable method for Equivalent Static Density (ESD) prediction.

3. A new viscometer has been designed which has met a higher design criteria for HPHT fluid testing 40,000 psig and 600F.

4. An accurate hydraulics program calibrated with down-hole pressure gauge coupled with a temperature simulator is a critical tool.

5. A methodology is required to accurately predict a constant hydrostatic overbalance when the well temperature profile is the geothermal gradient.

6. Once the minimum overbalance is determined, the standard temperature for surface mud weight must be defined. Thereafter the mud weight is maintained within a matrix which references the standard weight at the standard temperature.

7. The standard temperature concept has proved to be useful in controlling the surface mud weight.

8. There is an optimum S/W ratio, at which minimum barite sag will be experienced. The optimum S/W ratio is mud system dependent, which should be determined for the given operating conditions.

9. Mud should be calibrated and maintained with 100-rpm reading instead of the lowest PV.

10. The mud balance must be properly calibrated using the new established method. HPHT drilling cannot afford much error in intended mud weight due to wrong measurements.

11. The rig crew should be briefed by the fluid engineers on procedures that differ from previously accepted practice and the role that they have to play in management of bottom-hole pressure.

12. The mud temperature must be reported with any mud weight measurement.

13. Due to the reduced hydrostatic overbalance, particular care must be exercised immediately after stopping circulation. Any operations which have the effect of reducing the bottomhole mud pressure must be carried out carefully.

14. Continuity of key personnel is also important.

15. Use of cesium formate brines, a low-solids, non-halide, high-density fluid which has a good reputation as a shale drilling fluid has met expectations.


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Source: Ron et al. SPE 103731




Figure 5: Kill mud weight versus temperature (kill mud weight = 945 pptf @ 120 Deg F). Source: Erhu Gao et al. SPE 50581

Figure 4: Surface mud weight versus temperature (surface mud weight = 915 pptf @ 120 Deg F). Source: Erhu GAO Et al. SPE 50581

Mud Design in HPHT

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