Thursday, March 29, 2018

Seismic Surveillance for Monitoring Reservoir Changes

Time-lapse images and acoustic listening devices are the latest tools of the trade for tracking reservoir fluid movement. These techniques, done with both active and passive seismic surveys, are presenting new ways of getting more from the reservoir. For years operators have developed sophisticated models of how fluid moves in reservoirs. However, checking and calibrating them against field measurements often meets with limited success. Sample points may be far apart or data hard to interpret. Now seismic surveillance offers high-quality data that might dramatically improve reservoir management. 

Seismic surveillance is a way to "watch" and "listen" to movement of reservoir fluids far from borehole. Knowing how fluid distribution changes over time is important for more effective management decisions. For example, tracking fluid contacts during production can confirm or invalidate flow models and thereby allow the producer to change recovery schedules. Mapping steamflood fronts during enhanced oil recovery (EOR) can point to bypassed zones that may become targets of remedial operations. Mapping hydraulic fractures reveals the local stress field, which can govern permeability anisotropy - vital input for well placement, stimulation treatment and waste disposal. Seismic monitoring sheds light on each of these problems by taking advantage of some traditional and some not-so-traditional techniques.

The methods for watching and listening to movement of reservoir fluids depend on the rate at which the movement takes place. For changes over months or years, as in the case of a moving gas-oil contact (GOC), the method of choice is time-lapse seismic, sometimes called four-dimensional (4D), differential, repeated, seismic. Images from traditional seismic surveys taken before and after production are compared, and the difference attributed to moved fluids. 


For changes taking place over microseconds to minutes -as when fractures are induced or when fluid flows through natural fractures -the technique is to use borehole sensors to localize the cracking noise produced by fluid movement. These sensors record signals from events similiar to tiny earthquakes, and much of the data analysis is borrowed from earthquake technology. 

As reservoirs are exploited, pore fluid undergoes changes in temperature, pressure and composition. For example, enhanced recovery processes such as steam injection increase temperature. Production of any fluid typically lowers fluid pressure. Gas injection and waterflooding mainly change reservoir composition. These fluid changes affect the bulk density and seismic velocity of reservoir layers. Changes in velocity and density combine to affect the amplitude and travel times of reflected waves. Most surface seismic monitoring is based on amplitude changes rather than travel time. The key is to have amplitude changes big enough to be seen between the baseline survey and subsequent surveys.

The expected change in seismic amplitude can be estimated from laboratory data. Most of the amplitude change comes from fluid effects on rock velocity rather than on rock density. Laboratory experiments on fluid-filled rock show that the greatest changes in velocity arise from two different phenomena - introduction of gas into a liquid-filled rock or an increase in temperature of a hydrocarbon-filled rock. Both cause a decrease in seismic velocity. Even a small amount of gas decreases velocity dramatically by making the fluid compressible. At higher temperatures, hydrocarbons become less viscous, reducing overall rigidity. Both effects are prominent at low pressures, such as in shallow, unconsolidated sands.

Monitoring EOR processes such as steamflooding and in-situ combustion using 4D seismic was first performed in the 1980s. The progression of temperature and gas fronts away from injection wells was mapped using seismic amplitude difference sections- a seismic section created by subtracting the baseline survey image from the monitor survey image. Cores taken after treatment provided independent verification on the extent of flooding - the steam had caused additional hardening and cementation.

These studies established the basic technique used today. The baseline and subsequent surveys must be acquired and processed in the same way. However, repeating a survey with the same sources, receivers and positioning is nearly impossible. Additional processing, therefore, is used to correct for these and other undesirable diffirences in the two surveys caused by weather, access or surface structures. To intepret amplitude differences in terms of fluid movements requires a calibration, obtained by matching reflection amplitudes outside the reservoir. Interpreting amplitude changes in terms of reservoir fluid changes is then a visual, qualitative step.

A more quantitative way of using 4D seismic to monitor fluid movement is to include sythetic seismic sections and reservoir fluid flow simulations in the calibration and interpretation. Norsk Hydro is using this technique to track a gas-oil contact during gas injection. Two 3D surveys were acquired 16 months apart in the Oseberg field, Norwegian North Sea. Special care was taken to preserve true amplitudes during processing. The base survey served several purposes : it provided structure for the initial reservoir model and input for further drilling and development decisions as well as acoustic properties of lithologies and fluids. 

Injecting gas into the Oseberg field pushes the GOC deeper and farther from the injection well. This displacement agrees with that shown on surface seismic and with the simulated reservoir fluid flow for the period between the seismic survey. 







Borehole seismic images from the field support the interpretation. Time-lapse verticaal seismic profiles (VSPs) from the same well also show downward movement of GOC.
The sequence of seismic data interpretation, modeling and comparison with reservoir fluid flow models forms a loop, taking advantage of feedback at many stages. Using these steps, Norsk Hydro geophysicst have been able to validate the existing reservoir model and develop a methodology for future monitoring.



 A monitoring technique that is just emerging is comparison of amplitude variation wtih offset (AVO) in repeated surveys. AVO analysis has been shown to be a powerful fluid discriminator. Scientist at Elf Aquintatine have mad some progress in testing this technique for monitoring waterfront movement in the Frigg field, Norway. The Frigg has producing wells at the crest of the structure, but little other than seismic data to describe the rest of the reservoir. Accurate estimates of gas reserves are crucial so that delivery contracts can be honored. 

Real-Time Monitoring

Real-time monitoring is a different kind of seismic surveiilance that goes by three names: microseismic monitoring, acoustic emission monitoring, or passive seismics. Pressure jumps caused by fluid injection, depletion or temperature change are rapidly transmitted to surrounding rocks, causing stress changes. Stresses are released by movement at fractures or zones of weakness through microseismic events - tiny earthquakes. Typically, microseismic events have very small magnitudes , from -6 to -2 on the Richter scale, a logarithmic measure of energy released in a seismic event. Most microseismic events have a million times less energy than the smallest earthquake that can be felt by a human at the Earth's surface, which is +2 to +3. However, some reservoirs have a history of felt seismicity induced by human intervention.

The transient nature of pressure changes requires a different approach to monitoring. Sensor are deployed in boreholes, adapting technology first developed to monitor earthquakes, then for fractures created by hydraulic stimulation of hot, dry crystalline rocks for extraction of geothermal energy. In the case of hydraulic fracturing for wellbore stimulation and waste injection, passive seismics can provide information about orientation and now height and length of induced fractures, depicting fracture containment. With orientation information, well locations can be optimized to take advantage of permeability anisotropy associated with fractures, and waste containment can be assured for regulatory purposes.

 How does microseimic monitoring work? Although the mechanism of hydraulic fracturing is usually understood to be tensile failure , many microseismic experts believe that recorded events are caused by shear failure along fractures. Energy radiates as a compressional (P) wave traveling at the P-wave speed followed by a shear (S)wave traveling at the slower S-wave speed. A conveniently located triaxial borehole receiver records signals that may be analyzed to locate the source of the emissions.

Location is determined by distance and direction from the receiver. Distance to the event can be obtained by knowing the velocites of P waves and S waves and the lag between their arrivals. Direction is known from polarization or particle motion of the P wave, which is along the path connecting the event and the receiver. 

Most microseismic monitoring experiments are conducted in dedicated observation wells near an injection well and away from noisy pumps.

 

 
 

Monday, March 26, 2018

The MDT Tool

In the MDT tool, unwanted fluid is expelled from the tool using the pumpout module. During sampling, the engineer can monitor the resistivity and temperature of fluid in the flowline while pumping it directly into the borehole or into a dump chamber. When fluid quality is judged to be representative of the reservoir, the pump is stopped and pure formation fluid can be diverted to the sample chamber or, if a sample is not required -often the case when formation water or gas is indicated -another zone can be tested. 

To prevent gas from coming out of solution during sampling, pressure is maintained above bubblepoint using throttle valves in the sample chambe controlled by surface software. Maintaining pressure above bubblepoint reduces drawdown, which helps prevent crumbling in soft formations. Excessive drawdown can result in seal failure and hence mud contamination of a sample. Drawdown can also be limited by using a water cushion and choke with the multisample module.

Formations in which seal failures are likely- highly laminated or otherwise heterogeneous formations -or formations that have low permeability can be tested and sampled using the dual-packer module. Instead of a probe and packer to provide a seal, two inflatable packers are used to isolate an interval of about 3 ft of ormation forming a mini drillstem test. The pumpout module is used to inflate the packers and also to expel mud from between the packers before sampling.

 

Friday, March 23, 2018

Downhole Optical Analysis of Formation Fluids

In the past, wireline formation samplers have not been able to see the fluid they were sampling. Downhole optical analysis of fluid before sampling removes the blindfold to reveal oil, water or gas. The sample chamber needs to be opened only when the desired fluid is present. 

Bringing formation fluid samples to the surface for examination was a novel wireline advance when it was introduced in the early 1950s. Run in open hole or cased hole, the Formation Tester (FT) took a sample of formation fluid where analysis of earlier runs of resistivity and porosity logs showed promising zones. The FT consisted of a sealing packer and probe system that could be set against the formation. Once this was set and opened, formation fluid drained into a sample chamber. The entire sampling operation, from set to retract, was monitored using a pressure gauge. The sample chamber was closed only when pressure stopped increasing -implying the chamber was full and at formation pressure. 

The FT's probe and packer could be set only once per trip in the hole. This created a couple of problems. If the formation has low permeability, the sample chamber could take hours to fill, delaying rig operations and increasing the risk of the tool becoming stuck. Sampling in low-permeability formations was therefore often aborted. But sampling also had to be aborted if the seal between packer and borehole wall failed, indicated by a sudden increase in sampling pressure to hydrostatic. The only remedy was to pull out of the hole, redress the tool and try again. The next generation of testers addressed these difficulties.




The RFT Repeat Formation Tester tool, introduced in the second half of the 1970s, allowed an unlimited number of settings or pretests before sampling was attempted. Pretest chambers were used to indicate the permeability and to check for seal failures. During a pretest two small volume chambers opened producing pressure drawdowns. Knowing the amount of drawdown for each chamber gave two estimates of permeability. Once the pretest chambers were filled, formation permeability could also be calculated from the subsequent buildup to formation pressure. Sudden  incrase to hydrostatic pressure during a pretest showed seal failure. Testing the formation first allowed sampling to be carried out in zones where seal failures did not occur and where permeabilities were high enough to allow one of two sample chambers to be filled in a reasonable amount of time.

However, RFT samples suffered important limitations: the sample too often contained a large percentage of mud filtrate and the flowing pressure sometimes dropped below bubblepoint changing the sample characteristics. Even when the sample was formation fluid, it could have been water or gas and of no interest to the oil company. The latest generation formation tester , the MDT Modular Formation Dynamics Tester tool, overcomes these problems. 





Thursday, March 22, 2018

Exploration Technology in an Era of Change



"We've got to be careful how we define economic. Advances in technology make what is uneconomic today economic tommorow. Take deep water development. Five years ago we would have said a water depth of 4000 ft [1220 m] in the Gulf of Mexico is a no-no. Now, no problem. So when we talk about economic elephants, we are often talking about waiting for development technology to catch up to make those elephant economic. And the technology is catching up rapidly."


 "I'd like to offer a dissenting opinion and address the onshore prospects that a smaller company can deal with. I believe that if there are large fields left in the US, they are probably low-resistivity pay and stratigraphic traps that are virtually invisible to conventional technology. A lot of bright people have looked for oil and gas in the US, using mostly 1975-vintage technology. Very few explorationist have been equipped with a scanning electron microscope,modern seismic surveys, and expert petrography and log analysis. Very few know how to apply hydrodynamics or surface geochemistry. This is one of the great opportunities still left for "value-added production" - perhaps not on the scale of finds in Indonesia or Africa, but important nonetheless." 

" We think of multidisciplinary integration as a core competency - we are only as good as our ability to develop options based on our multidisciplinary evaluation of data. Accessing technology, with a capital "T", we do mainly by looking to the outside world. 
We think about exploration Technology in broad terms. We line up our technology under three banners : (1) techniques that reduce finding and development costs, (2) those that shorten the time between discovery and production, and (3) those that improve fluid recovery. For us, 3D seismic plays a role in all three categories and increasingly is routinely integrated with other data. "




" I think the major change for us was the power of integrating geochemical with geological, reservoir geophysical and other kinds of data on the workstation and the linkage of many workstations and data bases. The interpreter or interpreting team has access to a variety of information and modeling software, including balancing geologic sections, basin modeling. This approach requires more teamwork and further integration of staff specialist in the exploration and development process."

"There is another technical challenge that I alluded to earlier: finding all those now-invisible stratigraphic traps. Sequence stratigraphy is a key to some problems. For gas wells, an understanding of overpressure is essential. "







"We bypassed several reservoirs in Nigeria and the US Gulf Coast because they were not recognized on the logs. We discovered them by doing reservoir geochemistry on cores. The methods don't work so well on cuttings, so we are trying to collect more sidewall cores in problematic areas. The geochemistry itself is cheap- about $150 per sample."






Wednesday, March 21, 2018

Paleomagnetics for Logging

Nobody knows exactly why the earth's magnetic field switches polarity, but the fact that it does and for variable a new logging method enabling well-to-well correlations and the potential for absolute age determination in basin core. When rocks are formed, those that are magnetically susceptible record the direction and magnitude of the this remanent magnetism, the primary objective of paleomagnetic research , has now been applied to the borehole.



The earth's magnetic field is believed to be generated by some form of self-exciting dyanamo. This happens within the earth's iron-rich liquid outer core as it spins on its axis. Fluid motion in the liquid part of the core and activity in central solid part, give rise to local perturbations of the earth's field and also lead to variations in pole positions lasting from 1 year to 10^5 years. Even more intriguing is that complete reversals of the magnetic field occur-north pole becomes south pole and vice versa. These geomagnetic polarity reversals take about 5000 years to complete and last from 10^4 to 10^8 years. Nobody knows the cause, but the reversal process does not involve the magnetic pole simply wandering from north to south. The magnetic field strength appears to fade close to zero and then gradually increases in the opposite direction until a complete reversal is achieved.

How do we know all this? Records of Earth's magnetic field strength and direction date back only a few hundred years and do not show reversals. The first proof of a geomagnetic reversal was provided in 1906 by a French physicist, Bernard Brunhes, when he discovered volcanic rocks at Pontfarein in the French Massif Central that were magnitized almost exactly in the opposite direction to the present-day geomagnetic field. This led to the belief that rocks could retain magnetization from previous magnetic fields, a phenomenon called natural remanent magnetism (NRM).

If no remagnetization occurs - remagnetization is a possibility if rocks are reheated, exposed to later magnetic fields or chemically altered- NRM is an imprint of the geomagnetic field existing at the freezing time of lavas or at the deposition time of sedimentary rocks. And, unlike most geological events, the direction of the NRM imprint is the same worldwide. Traditional dating techniques, such as isotopic or biologic methods, and accurate NRM measurements allow comparison of geochronological time scales with polarity reversals. 




Because of the random time distribution of polarity reversals, a sequence of four or five is unique, almost like a bar code.  A borehole reading of this magnetic reversal sequence (MRS) promises a direct correlation with GPTS. Because MRS is measured against depth and GPTS against time, correlation between them infers a sedimentation rate. 

During the formation of a basin, sedimentation rate varies, but the variation is not random and it is strictly independent of changes in magnetic polarity. This means that sedimentation rate must not exceed a limit compatible with the lithology and must not change drastically at each reversal. Hence, the rate can not only be determined, but can also be used to check the quality of match between one MRS and another or between MRS and the GPTS.





Correlations that indicate a fluctuating sedimentation rate may either be incorrect or may indicate unconformities where part of the geological record in the MRS is missing.

Magnetic reversal sequences can also be used to provide well-to-well correlation. In a hypothetical example representing a series of coastal onlap sequences, the main limits of sedimentary bodies have been determined. Accurate time correlations are now possible and cleary show zones where sedimentation is continous and those where unconformities. Combining both sets of data provides a complete sedimentary description of the basin. The relationship between sedimentary bodies is shown to be more complex than originally assumed.

Basics of Paleomagnetism
Natural remanent magnetism is mostly carried by ferromagnetic minerals, such as iron oxides (hematite, magnetite, goethetie) and iron sulfides (pyrrhotite, but not pyrite), that have high magnetic susceptibility, meaning they are easily magnetized in the presence of a magnetic field. Unlike paramagnetic minerals such as clays, which have small positive susceptibility, or diamagnetic minerals such as limestone or sandstone, which have slightly negative susceptibility, ferromagnetic minerals retain some magnetism after the magnetic field is removed.


 



Wednesday, March 14, 2018

Measurements at the Bit: MWD Tools

Measurements-while-drilling technology has moved down the drillstring to enlist the bit itself as a sensor. 






Conventional drilling of high-angle and horizontal wells is like piloting an airplane from the tail rather than the cockpit. Information required to land the well in the target formation is derived from sensors 50 ft or more behind the bit or at the surface. Because these measurements -about well trajectory, drilling efficiency and formation properties -are remote from the bit, crucial drilling decisions are delayed and data may require more complex interpretation. In particular, course corrections are delayed by lag in measurements needed to make steering decisions, resulting in less drainhole in the pay zone. Also, maximum drilling efficiency requires information about mechanical power delivered to the bit, which is inferred from surface measurements, degrading its accuracy. And resistivity measurements from logging-while-drilling (LWD) sensors in drill collars are limited to formation resistivity less than 200 ohm-m.

Despite these limitations, horizontal and high-angle drilling have proved successful, especially in simple geologic settings - uncomplicated layer-cake structure. Nearly, all these  wells start vertically, with a conventional rotary bottomhole assembly (BHA). The drillstring and bit are rotated from the surface either by a rotary table on the derrick floor or a motor in the traveling block, called a topdrive. Drilling this way is called rotary mode. To kick-off from vertical, the rotary assembly is replaced with a steerable motor - usually a positive displacement motor, driven by mud flow, in a housing bent 1 degree to 3 degree. When mud is flowing , the motor rotates the bit, but not the drillstring. This type of drilling is called sliding mode, because the drillstring slides along after the bit, which advances in the direction of the housing below the bend. 



The direction in which the bit is pointing, called toolface, is measured and sent to surface by measurement-while-drilling (MWD) equipment for real-time control of bit orientation. Measurements include azimuth, which is the compass bearing of the bit, and inclination, which is the angle of the bit with respect to vertical. Large changes in direction are made by lifting off bottom and reorienting the bent sub by rotating from surface. Small changes are made by varying weight on bit, which changes the reactive torque of the motor and hece toolface orientation.



Once sufficient inclination has been built, straight or tangent sections can be drilled in several ways. One is with a conventional rotary, or "locked" , assembly, which is rigid enough to allow fast, straight drilling. Small adjustments in inclination can be made by varying weight on bit or rotary speed. Most horizontal sections, and some tangent sections, are drilled with a steerable motor while rotating the drillstring from surface. In this mode, the steerable motor behaves like a rotary BHA, maintaining both azimuth and inclination. 

However, the presence of the steerable motor allows the driller to make course corrections without tripping the drillstring out of the hole. 




Generally, the driller tries to make as much hole as possible using a rotary assembly or a steerable motor in rotary mode. Rotation of the drillstring reduces the risk of getting stuck and allows faster drilling than in sliding mode.



Overcoming limitations in horizontal drilling

Today, the ability to drill horizontally is undisputed. Yet, the efficiency of drilling and steering horizontally is limited by the distance between the bit and measurements. In drilling, for example, one way to define efficiency is the ratio of time spent making hole to the total rig time, including operations such as trips or hole conditioning. In the horizontal section, steering efficiency can be defined as the ratio of the length of the horizontal section in the pay zone to the total length of the horizontal section. How does lag between measurements and the bit limit these efficiencies?


In drilling with a downhole motor in rotary mode, a key limitation on efficiency is how much weight the driller can safely apply to steerable motor. As the driller increases weight , the motor produces more torque, and power is torque times RPM. The more power, the faster the rate of penetration -up to a point. Excess weight may stall and eventually damage the motor, requiring an expensive trip for motor replacement. The goal is to apply as much power as possible, but within the operational limit of the motor. Power is estimated conventionally from surface measurements of mud flow and mud pressure. Motor RPM is roughly proportional to mud flow. Torque is roughly proportional to the increase in the mud pressure when the bit is on the bottom, compared to off bottom. 

Perhaps the greatest limitation in conventional horizontal drilling is in steering efficiency. Wells are conventionally steered "geometrically" - along a path that has been predetermined based on nearby well data and geologic assumptions. Steering is based only on bit direction and inclination data. Gamma ray and resistivity measurements, if present, are made far from the bit and used only retrospectively. This technique is fine, as long as the target is thick, structurally simple and well known. But it is less effective when the target is thin, complex or insufficently known for planning the well trajectory. And increasingly, with advances in three-dimensional seismics, operators are locating more intricate reservoirs and drilling more complex wells. Challenges today include thin beds and complexly folded or faulted reservoirs.

In these settings, sensors in drill collars allow replacement of basic geometric steering with more efficient geologic steering, or "geosteering" - navigation of the bit using real-time information about rock and fluid properties. A North Sea example shows how LWD sensors performed the dual purpose of geosteering and formation evaluation. Using mostly resistivity measurements, the driller geosteered a drainhole along the top of the oil/water contact to avoid gas production. Resistivity modeling from offset wells showed this contact should have a resistivity of about 0.6 ohm-m. When the value dropped, indicating water , the well path was turned up slightly; when resisitivity increased, the well path was dropped slightly.  

In addition to reduced efficiency in drilling and geosteering, a third limitation of conventional horizontal drilling is in formation evaluation while drilling. Logging-while-drilling sensors reach the formation long before wireline measurements, and so generally view it before wellbore degradation, but some invasion has still occured. Rapid invasion, called spurt, may mask true resistivity in some formations. Also, LWD resistivity measurements by the CDR Compensated Dual Resistivity tool are limited to environments favoring induction-type settings -resistive mud (fresh or oil-base mud) and conductive rock.

The solution to these problems -limited efficiency in drilling and geosteering, and limited capabilities of real-time formation evaluation - is relocation of drilling and logging measurement to the bit itself. The system includes two new logging devices : the Geosteering tool , an instrumented steerable downhole mtoor and the RAB Resisitivy-At-the-bit tool, an instrumented stabilizer. Measurements include gamma ray, several types of resistivity including a measurement at the bit, and drilling data such as inclination, bit shocks and motor RPM. 




The technical leap that allows measurements to be made at the bit and below the steerable motor is a wireless telemetry system. This telemetry link sends data from sensors near the bit to the MWD tool up to 200 ft behind the bit, a path that bypasses the intervening drilling tools, such as the steerable motor. The PowerPulse MWD system recodes and then sends data to surface in real time using mud-pulse telemetry at up to 10 bits per second. At surface, data recording, interpretation and tool control are performed by the Wellsite Information System. Control data can be sent from the surface back downhole by varying mud pump flow. 

The geosteering tool enables the driller and geologist to make real-time correction at the bit, detect hydrocarbons at the bit and steer the borehole for increased reservoir exposure. Both tools measure gamma ray, resistivity using the bit as electrode, and "azimuthal" resisitivy - focused at a narrow angle along the borehole wall. 

Resistivity at the bit is measured by attaching the Geosteering or RAB tool directly to the bit and driving an alternating electric current down the collar, out through the bit and into the formation. The current returns to the drillpipe and drill collars above the transmitter. In water-base mud, returning current is conducted from the bit through the mud, into the formation and back to the BHA. In oil-based mud, which is an insulator, current returns through the inevitable but intermittent contact of the collars and stabilizers with the borehole wall, leading to a qualitative indication of resistivity. Formation resisitivy is obtained by measuring the amount of current flowing into the formation from the bit, and normalizing it to the transmitter voltage. 






Azimuthal resistivity is measured from one or more button electrodes and , like the azimuthal gamma ray measurement, can be used to steer the bit. Both tools can be oriented in multiple directions to find the location of a lithologic or pore fluid boundary relative to the borehole -up, down, left or right - and thereby steer the bit. 

Surface Control for Measurements at the Bit

Because the Geosteering tool is an instrumented steerable motor, it enables the driller to steer the bit on a geometric or geologic path through the pay zone.  The driller's window into the bit is the Wellsite Information System, which includes a display for checking and revising the structural and stratigraphic model, and updating the drilling trajectory. This screen is intended mainly for real-time management of horizontal drilling. 

 Resolution of both Geosteering tool and RAB Resistivity measurements is sufficient for hydrocarbon detection and lithologic correlation. The multiple depths of investigation and high resolution of the focused RAB measurements also provide formation evaluation-quality information. Applications include prompt location of coring and casing points, and monitoring of invasion by logging after drilling.









Thursday, March 1, 2018

Drilling and Testing High Pressure High Temperature Wells

High-temperature, high pressure (HTHP) wells present special challenges to drill and test. Predominantly gas producers, HTHP wells may yield significant reservers in some areas. But the wells stretch conventional equipment beyond normal operational capacities. To safely meet these extreme conditions, traditional procedures have been modified and extra operational controls devised. 

 What constitutes HTHP is debatable. Perhaps the best definition has been coined by the UK departemen of energy:
"wells where the undisturbed bottomhole temperature at prospective reservoir depth or total depth is greater than 300 F (150 degree celcius) and either the maximum anticipated pore pressure of any porous formation to be drilled exceeds a hydrostatic gradient of 0.8 psi/ft or pressure control equipment with a rated working pressure in excess of 10,000 psi is required.

HTHP drilling is not new. In the late 1970s and early 1980s, many gas wells were drilled in the Tuscaloosa trend, Lousiana, USA, and other southern US states. These encountered temperatures above 350 degree F (177 C) and presures of more than 16,000 psi, not to mention highly corrosive environments. When HTHP interest switched to the North Sea in the mid 80s, new hazards were introduced. The wells were drilled offhsore, in exteremely hostile conditions and sometimes using floating semisubmersible rigs rather than fixed jackups.

Most of the North Sea HTHP wells are situated in the Central Graben - a series of downthron and upthrown blocks.  

The Central Graben contains several Jurassic gas condensate prospects at 12,000 to 20,000 ft [3660 to 6100 m] , with pressures of 18,000 psi or more and temperatures of up to 400 F [205 C].



 Water depth in the Central Graben varies between 250 to 350 ft [75 to 105 m] . Both jackups and semisubmersibles have successfully drilled wells in the sector, harsh environment jackups up to about 300 ft and semisubmersibles for deeper water. Jackups offer the advantage of contact with the seabed, eliminating heave and simplifying many drilling and testing operations. On the downside , in an emergency , jackups cannot be moved off location quickly. Also, few deepwater jackups are available.

This article looks at three key areas of HTHP operations in the UK Central Graben: drilling safety, casing and cementing, and testing. It also examines how North Sea experience has been used to help convert a jackup to drill demanding wells off Brunei. 

Drilling Safety

Preventing and controlling influxes of reservoir fluid into the well -called kicks- are always central to drilling safety, but in HTHP wells the dangers from a kick are amplified. The volume of a HTHP gas kick remains virtually unchanged as it rises in the annulus from 14,000 to 10,000 ft [4265 to 3050 m]. From 10,000 to 2000 ft [610 m] its volume triples. But from 2000 ft to the surface, there is a hundred-fold expansion.

Put simply, a gas influx of 10 barrels at 14,000 psi becomes 4000 barrels under atmospheric conditions. As reservoir fluid rapidly expands, it forces mud out of the well -unloading - reducing mud in the well, cutting hydrostatic pressure at the formation, allowing additional reservoir fluids to enter, and ultimately causing a blowout.

Wells drilled in the Central Graben have another complication - an unpredictable and sharp increase in pore pressure over a short vertical interval, sometimes less than 100 ft [30m]. And, while the pore pressure may rise rapidly, the fracture pressure does not. In some cases, convergence of pore and fracture pressures means that a small decrease in the mud weight of 0.5 pounds per gallon [lbm/gal] or less changes the well from losing circulation to taking a kick.

The difficulty of drilling in the Central Graben was highlighted in September 1988 when a blowout on the semisubmersible Ocean Odyssey resulted in fire and loss of life. Consequently, the UK Department of Energy esentially banned the drilling and testing of prospects with anticipated reservoir pressures exceeding 10,000 psi.



Because the consequences of failure in HTHP wells are so great, worst-case scenarios tend to be more conservative than for normal wells. Usually, the maximum anticipated size of a kick is set at the limit of detection -often 10 to 20 barrels. In HTHP wells, many contigency plans are based on the worst case of an influx completely filling the well at reservoir pressure.

When drilling with oil-base mud (OBM), there is a likelihood that gas entering the wellbore will dissolve into the mud's oil phase. This affects how the kick moves up the annulus and may mask detection. Since 1986, researchers at Schlumberger  have been studying the behavior of gas kicks, particularly in OBM. 

Planning requires realistic data: well temperature profile, nature of the anticipated reservoir fluids, expected maximum bottomhole pressure and pressure gradient, and rock strength and permeability. These are most often estimated using offset data -relatively plentiful in the North Sea. But where offset data are sketchy, predictive modeling may be employed. Shell has developed a model to predict rock strength and pore pressure in many areas of the North Sea. Shell has also modified a model designed to predict wellhead temperatures in offshore production wells to estimate surface equipment temperture when controlling a kick. 

Worst-case scenarios are used not only to specify equipment but also to draw up specific operational procedures, for example detailing what to do if the well takes a kick. Training is then used to comunicate these procedures to drilling personnel. Long before drilling starts, specific HTHP training courses may be run. Once on the rig, there are prespud meetings, crew safety meetings before starting key sections of the well, preshift meetings to discuss the current situation, and regular drills to practice important techniques like closing blowout preventers (BOP).

The three issues at the heart of HTHP drilling safety are kick prevention, kick detection and well control.

The best way of avoiding well-control problems is to anticipate situations known to precipitate kicks and take preventive action. Here are four examples:
  • When high-pressure formations are drilled, kicks commonly occur when the drilling assembly is being pulled out of hole. The movement of the assembly creates a piston effect reducing pressure below the bit, called swabbing. A time-consuming routine is usually adopted to check whether swabbing will cause an influx.
  • Before the assembly is pulled out of hole, the mud at the bit is circulated to surface - a procedure called circulating bottoms up. If this is free from gas, ten stands of drillpipe are pulled. The string is then run back to total depth (TD), and bottoms up are circulated. Gas in the mud is measured again, with an increase indicating swabbing. If swabbing does cause an influx, the mud weight may be raised slightly and the string pulled out of hole more slowly. Also, circulating mud while pulling out of hole helps stop swabbing -a process made easier by topdrive. 
  • The combination of relatively high-viscosity mud, deep wells and small annular clearences leads to higher than normal friction pressure during mud circulation. At the formation, mud hydrostatic pressure and friction pressure then combine to give the equivalent circulating density (ECD). This may be designed to balance formation fluid pressure. But during a connection, mud flow stops and friction pressure is zero. Witch reduced ECD, small quantities of gas, called connection gas, may permeate from the formation. 
  • Kicks don't occur just during drilling coring also causes problems. The relatively small clearence between core barrel and open hole increases the possiblilty of swabbing when pulling out of hole. This may be combated by limiting the amount of core cut any one time - usually to 30 ft or less - and pulling out of hole very slowly, checking for flow and monitoring gas in the mud.
  • Tight margins between pore pressure and rock strength ,as in the Central Graben, make lost circulation common, complicating well control. The normal practice on encountering losses is to pump lost circulation material (LCM) in the mud. If LCM fails to block the formation, the strategy is to pull out of hole, run back in with open-ended pipe and spot cement across the loss zone. Some slurry is squeezed into the formation and, once set, the remainder drilled out. However, in HTHP wells, the swabbing effect of pulling the bottomhole assembly out of hole prior to spotting the plug may induce a kick elsewhere in the wellbore. In this case, the only solution is to spot the cement plug through the bit. To make this easier, rotary drilling is favored, rather than using a downhole motor that may clog up with cement.

 Kick Detection: Because no technique can guarantee kick-free drilling, influx detection remains vitally important. Traditional influx detection relies on observing mud level increases in the mud pits, or performing flow checks - stopping drilling to see if the well is flowing. Comparisons of mud flow rates into and out of the well are also used. To make detection more reliable, transfer of mud into the active system is tightly controlled and usually not allowed while drilling.

Recently, Anadrill has introduced the KickAlert early gas detection service based on the principle that acoustic pulses created by the normal action of the mud pumps travel more slowly through mud containing gas they do through pure mud. The pulses are measured as pressure variations at the standpipe as the mud enters the well and at the annulus as it comes out. If the well is stable and no gas is entering, the phase relationship between the pressure pulses in the standpipe and annulus is constant, or changes gradually as the well is drilled deeper. When gas enters, the pulses travel much more rapidly up the annulus, dramatically changing the phase and setting off an alarm on the drillfloor. 

 The presence of high-pressure gas may also be indicated by changes in drilling conditions. Increases in rate of penetration, torque or mud temperature in the mud return flowline on surface may all signify the onset of a kick. Computerized monitors help drilling personnel keep track of trends and spot abnormal situations using quick-look interpretations on a drillfloor screen.

Well Control: As soon as a kick is detected, drilling is stopped and the well is shut in. The influx must then be circulated out while keeping the presssure under control. 
The BOPs are the primary means of well closure. Once a kick is suspected, the annular blowout preventer is first closed. A flexible rubber element is inflated using hydraulic pressure, and is sufficiently flexible to seal around any downhole equipment. When it has been established that no tool joints are in the way, the pipe rams are then shut, sealing around the drillpipe. Now mud can no longer return through the flowline to the shale shakers and mud pits. Instead it must travel through the chokeline to the choke manifold, which is used to relieve mud pressure at surface.

The capacity of a BOP to resist pressure depends on the elastometric seals inside the rams and their likelihood of not being extruded. As temperature increases, extrusion becomes more likely. Seals may have to withstand prolonged temperatures that top 400 degree F - beyond the limit of ordinary components. Finite-element analysis has been used to identify which areas of the BOPs are most affected by heat and which seals need special elastomers rated to 350 degree F. 

Once the BOPs and choke are closed, pressure builds in the annulus and drillpipe. The maximum drillpipe pressure is used to calculate bottomhole pressure, which is used to plan the kill strategy. Well-kill strategy also takes into consideration the drilling operation underway during the kick.

If the kick occurs during drilling, weighted mud - either from a premixed or specially prepared supply - may immediately be pumped down the drillpipe. The formation fluid influx is gradually displaced up the annulus, expanding as hydrostatic pressure decreases. At surface, the mud-influx mixture travels to the choke manifold via the chokeline and has its pressure reduced by the choke. The well is slowly brought under control by carefully selecting mud weight and choke opening.

Casing and cementing 

In Central Grabben wells, choosing the location of the intermediate -usually 9 5/8 in. -casing shoe is crucial. Ideally, casing must be set above the high pressure reservoir and just below a zone of weak Hod chalk.





If it is set too high, the weak formation will be exposed to subsequent high pressure, and the only solution is to set a short, perhaps less than 100 ft, 7-in. drilling liner. This has the undesirable effect of reducing the diameter of further drilling.

Consequently, the  shoe is usually set at the bottom of the Hod chalk, in the Lower Cretaceous clays or in the Kimmeridge clay just above the reservoir. But finding the casing point is not easy - vertical seismic profile surveys may be employed. As drilling approaches the likely casing point, it is intermittenly halted, bottoms up circulated and cuttings examined by a geologist or micropaleogeologist.

Pressure is a key consideration when designing the casing string. The 9 5/8-in casing is often designed to withstand complete evacuation to atmospheric presssure with reservoir pressure in the annulus between open hole and casing. Given the high pressures, heavy-weight casing is usually required throughout the string.





Once the casing string has been run, the shoe must be cemented to resist the high reservoir pressure that will be encountered almost as soon as the next section of drilling starts. Location of the top of cement (TOC) of the 9 5/8 in. casing is sometimes an issue. I normal wells the TOC is usually above the previous casing shoe, with fluid trapped in the annulus above the TOC. When the HTHP wells are drilled, hot mud passing up the drillpipe-casing annulus heats fluid in the casing-casing annulus, causing it to expand.
For a subsea-HTHP well, the presure has no escape and it can burst or collapse the casing. For this reason, the TOC for 9 5/8 in. casing in a HTHP well is sometimes kept below the 13 3/8 in. shoe to allow annular pressure to dissipate into the formation.

In most HTHP wells a 7-in. liner is run, although in some cases it may be possible to cement a 7-in. casing to surface. In either case, the cement job must isolate the high-pressure zones to facilitate well testing. This requires good cementing practices and a carefully designed slurry.

Mud removal is vital in achieving strong cement bonding to the formation and casing, and sealing against high pressure. Even small quantities of contaminant in the cement slurry compromise the final setting strength. Spacers reduce contamination, but high temperatures may thin or destroy spacer polymers causing weighting agents to settle.

The tight pressure constraints found in HTHP wells mean that the traditional density hierarchy -  cement heavier than the mud with an intermediate spacer -is difficult to achieve without exceeding formation fracture pressure. A viscosity hierarchy is also desirable, but when cement is thicker than mud , the friction pressure may increase beyond the limit. This emphasizes the importance of other good drilling and cementing practices: drilling an even wellbore, circulating and conditioning the mud correctly, and centralizing the casing.



In gas zones with a low overbalance, there is the risk that high-pressure gas will enter the cement during hydration and create large channels. Elsewhere, loss of fluid into the formation reduces the slurry liquid-to-solid ratio, changing rheology, density and setting time.

Once the 7-in. liner is cemented, casing pressure tests simulate losing control during well testing and exposing the entire string to formation pressure. Test are generally carried out using a retrievable packer set above the theoretical top of cement in the annulus. 

Testing :

Cores are taken and logs run where possible and used to decide whether and where to test. Coring may be limited by its prospensity to swab the well and cause kicks. For logging, the tolerance of all standard wireline logging tools to high temperature may be boosted by thermal insulation.

Once  cores and logs have indicated the presence of hydrocarbons, a well test is needed to determine parameters like reservoir extent and permeability, and to sample reservoir fluid. In almost all cases, a cased-hole drillstem test is used. The well is normally shut in using a downhole valve and flow is controlled at surface using a choke manifold. Periods of flow and shut-in allow collection of data like flow rate and pressure changes. 

The rates and pressures experienced during testing HTHP wells are prodigious. One test by Ranger Oil Ltd. in the Centrl Graben using a jackup rig resulted in 44 MMscf/D of gas and 4400 B/D of condensate. The maximum recorded tubing-head pressure was 12,500 psi, the bottomhole temperature was 386 degree F (197 degree C.

Downhole Equipment:

Sealing off the candidate formation requires a packer. During an HTHP test, differential pressures across the packer may exceed 10,000 psi. For this reason, permanent packers are usually chosen, rather than  retrievable packers used in lower pressure test. With wireline (or very ocassionally drillipipe), the packer is installed complete with a sealbore, and a seal assembly is then run with the test string to seal into the packer.

Perforating with wireline guns is generally avoided during HTHP tests, so tubing-conveyed perforating (TCP) is preferred. Unlike wireline perforating, TCP allows the reservoir to be perforated underbalanced and immediately flowed through the test string.Because the guns will spend hours in the well prior to firing, high-temperature explosive is used. In most cases, the TCP guns are run as part of the test string, rather than hung off below the packer. This reduces the time that the explosives spend downhole and allows the guns to be retrieved in case of total failure. 



In most cases, test tools are operated using annular pressure. The condition of the fluid in the annulus, usually drilling mud, plays a critical factor. High-density, high-solids drilling fluid may plug pressure ports and reduce tool reliability. Solids may also settle, potentially sticking the test string. The effects on heavy, water-base mud of being static in a hot well have been thoroughly investigated in the laboratory and the performance of test tools has been improved to reduce downhole failures. In some cases, the annular fluid is changed to high-density brine, which is solids free but increases the expense of the test.