Tuesday, December 11, 2018

The Promise of Elastic Anisotropy

In certain rocks, sound waves travel at different directions. This characteristics, called elastic tence of aligned features such as fractures, microcracks, fine-scale layers or mineral grains. Combining anisotropy from petrophysics, geology and reservoir engineering may reveal a connection between these alignments and paths.

For most of this century, oilfield theory and practice assumed that waves propagate equally fast in all directions. That is, rocks have isotropic wave velocities.  But waves travel through some rock with different velocities in different directions. This phenomenon, called elastic anisotropy, occurs if there is a spatial ordering of crystals, grains, cracks, bedding planes, joints or fractures- essentially an alignment of strengths or weakness - on a scale smaller than the length of the wave. This alignment causes waves to propagate fastest in the stiffest direction. 

The existence of elastic anisotropy has been largely ignored by exploration and production geophysicist - and for good reasons. The effect is often small. With standard surface seismic measurement techniques most reservoir rocks show directional velocity differences of only 3 to 5% , which may often ben neglected. Moreover, processing data under the assumptions of an isotropic earth is already a challenge; the cost of adding the complications of anisotropy must be justified by improvements in the final seismic image. At most, anisotropy has usually been considered noise that must be filtered out, not as a useful indicator of rock properties.

However, with recent advances in acquisition, processing and interpretation of elastic data , the reasons for ignoring anisotropy are no longer valid. New acquisition hardware and measurement techniques designed to highlight anisotropy reveal highly anisotropic velocities in ultrasonic, sonic and seismic data. This article looks at the evidence for anisotropy, the best way to measure it, and how to use it to enhance reservoir description and optimize development. 

The two requirements for anisotropy - alignment in a preferential direction and at a scale smaller that of the measurement - can be understood through anologies. For the effect of alignment, imagine driving a car in an anisotropic city where streets in the north-south direction have a 30-mile-per-hour speed limit, while the east-west streets have a 50-mile-per-hour limit. East-west drivers will spend less time traveling a given distance than north-south drivers. And drivers will take east-west streets whenever possible. In an anisotropic rock, waves do the same thing, traveling faster along layers of cracks than across them. 

For the effect of scale, a less than perfect but interesting analogy is an insect on a leaf in a forest. The insect sees leaves and branches branching off in random direction : up, down, left, right and everywhere in between. A the scale of the insect, there is no preffered direction of tree growth. There are heterogenieties- sharp discontinuities between leaf and no leaf- but at the insect scale the forest is isotropic. However, to an insect a kilometer away from the forest, the trees appear neatly aligned vertically. To it, the anisotropic nature of the forest is revealed.

Similiarly, a small wavelength wave passing through a packet of thick isotropic layers of differing velocities senses the isotropic velocity of each layer.The wave sees discontinuities at each boundary , but if the wave is small enough to fit several wavelengths in every layer, the layers will still appear isotropic, and no alignment of the discontinuities will be apparent. However, a wave with a wavelength much longer than the layer thickness will not sample layers individually, but as a packet. The packet of layers act as an anisotropic material. The orientation of the layer boundaries is now perceived by the wave-and as one of the fastest directions of travel. And if the individual layers are made of aligned anisotropic grains, as is the case with shales, the anisotropic is even more pronounced.

Anisotropy is then one of the few indicators of variations in rock that can even must be studied with wavelengths longer than the scale of the variations. For once, using 100-ft [30-m] wavelength seismic waves, we can examine rock structure down to the particle scale. However, seismic waves are unable to determine whether the anisotropy is due to alignment at the particle scale or at a scale nearer the length of the wave. In the words of one anisotropy specialist, " The seismic wave is a blunt instrument in that it cannot tell us whether anisotropy is from large or small structures."

Two Types of Anisotropy

There are two styles of alignment in earth materials- horizontal and vertical - and they give rise to two types of anisotropy. Two oversimplified but convenient models have been created to describe how elastic properties, such as velocity or stiffness, vary in the two types. In the simplest horizontal, or layered , case, elastic properties may vary vertically , such as from layer to layer , but not horizontally. Such a material is called tranversely isotropic with a vertical axis of symmetry (TIV). Waves generally travel faster horizontally, along layers, than vertically. Detecting and quantifying this type of anisotroy are important for correlation purposes, such as comparing sonic logs in vertical and deviated dwwells, and for borehole and surface seismic imaging and studies of amplitude variation with offset (AVO).

The simplest case of the second type of anisotropy corresponds to a material with aligned vertical weaknesses such as cracks or fractures, or with unequal horizontal stresses. Elastic properties vary in the direction crossing the fractures, but not along the plane of the fracture. Such a material is called tranversely isotropic with a horizontal axis of symmetry (TIH). Waves travelling along the fracture direction- but within the competent rock-generally travel faster than waves crossing the fractures. Identifying and measuring this type of anisotropy yield information about rock stress and fracture density and orientation. These parameters are important for designing hydraulic fracture jobs and for understanding horizontal and vertical permeability anisotropy. 

More complex cases, such as dipping layers, fractured layered rocks or rocks with multiple fracture sets, may be understood in terms of superposition of the effects of t he individual anisotropies. 

Identifying these types of anisotropy requires understanding how waves are  affected by them. Early encounters with elastic anisotropy in rocks were documented about forty years ago in field and laboratory experiments. Many theoretical papers, too numerous to mention, address this subject, and they are not for beginners. However, it's easy to visualize waves propagating in an anisotropic material. First picture the isotropic case of circular ripples that spread across the surface of a pool of water disrupted by the toss of a pebble. In "anisotropic water" , the ripples would no longer be circular, but almost - not quite - an ellipse. Quantifying the anisotropy amounts to describing the shape of the wavefronts with terms such as ellipticity and anellipticity. In anisotropic rocks, waves behave similarly, expanding in nonspherical, not-quite ellipsoidal wavefronts. 

Waves come in three styles , all of which involve tiny motion of particles relative to the undisturbed material: in isotropic media, compressional waves have particle motion parallel to the direction of wave propagation, and two shear waves have particle motion in planes perpendicular to the direction of wave propagation.

In fluids, only compressional waves can propagate, while soilds can sustain both compressional and shear waves.  Compressional waves are sometimes called P waves, sound waves or acoustic waves, and shear waves are sometimes called S waves. The two are recognized as elastic waves. In a given material, compressional waves nearly always travel faster than shear waves.

When waves travel in an anisotropic material, they generally travel fastest when their particle motion is aligned with the material's stiff direction. For P waves, the particle motion direction and the propagation direction are nearly the same. When S waves travel in a given direction in an anisotropic medium, their particle motion becomes polarized in the material's stiff ( or fast) and compliant (or slow) directions. The waves with differently polarized motion arrive at their destination at different times - one corresponding to the fast velocity, one to the slow velocity. This phenomenon is called shear-wave splitting, or shear-wave birefringence - a term, like anisotropy, with origins in optics. Splitting occurs when shear waves travel horizontally through a layered (TIV) medium or vertically through a fractured (TIH) medium.

Since most geophysical applications place the energy source on the surface, waves generally propagate vertically. Such waves are sensitive to TIH anisotropy, and are therefore useful for detecting vertically aligned fractures. Any stress field can also produce TIH anisotropy if the two horizontal stresses are unequal in magnitude. Vertically traveling P waves by themselves cannot detect anisotropy, but by combining information from P waves traveling in more than one direction, either type of anisotropy can be detected. One approach is to combine vertical and horizontal P waves - such as those which arrive at borehole receivers from distant sources. Another technique compares P waves traveling at different azimuths. Two drawbacks to these compressional-wave methods are that horizontal wave propagation is difficult to achieve except in special acquisition geometries, and that travel paths for P waves are different, introducing into interpretation additional potential differences other than anisotropy. Shear waves, on the other hand, allow a differential measurement in one experiment by sampling anisotropic velocities with two polarizations along the same travel path, giving a greater sensitivity for anisotropy than P waves in multiple experiments. 

Compressional and shear waves of all wavelengths can be affected by anisotropic velocities, as long as the scale of the anisotropy is smaller than the wavelength. In the oil field, the scales of measurement parallel those in the analogy of the insect in a tree in a forest- the insect represents the ultrasonic scale, the tree trunk radius is similiar to the sonic scale and the height of the trees is the scale of the borehole seismic wavelength. The following sections describe how anisotropy is being used to investigate rock properties at each of those scales. 

At the Insect Scale

Wavelenghts in most sedimentary rocks are small - 0.25 to 5 mm for 250 kHz ultrasonic laboratory experiments, and they are four times smaller at 1 MHz. Ultrasonic laboratory experiments on cores show evidence for both layering and fracture related anisotropy in different rock types. While shales generally lead the pack in the relative between velocities of a given wave type in fast and slow directions, experimentalists no longer deliver laboratory results in such simple terms. Instead of the two numbers, P- and S-wave velocities, elastic properties are often characterized by plots of velocity variation around some axis of symmetry. This variation of velocity with angle of propagation has implications for the validity of many empirical relationships that have been established, linking velocity to some other rock property. 

Since ultrasonic laboratory measurements at 0.25 to 5 mm wavelength detect anisotropy, this indicates that the spatial scale of the features causing the anisotropy is much smaller than that wavelength. The main cause of elastic anisotropy in shales appears to be layering of clay platelets on the micron scale due to geotropism - turning in the earth's gravity field- and compaction enhances the effect. 

Laboratory experiments also show the effect of directional stresses on ultrasonic velocities, confirming that compressional waves travel faster in the direction of applied stress. One explanation of this may be that all rocks contain some distribution of microcracks, random or otherwise. As stress is  applied, cracks oriented normal to the direction of greatest stress will close, while cracks aligned with the stress direction will open. In most cases, waves travel fastest when their particle motion is aligned in the direction of the opening cracks. 

Measurements made on synthetic cracked rocks show such results. And computer simulations indicate that rock with an initially isotropic distribution of fractures shows anisotropic fluid flow properties when stressed. Fluid flow is greatest in the direction of cracks than remain open under applied stress, but the overall fluid flow can decrease, because cracks perpendicular to the stress direction, which would feed into open cracks, are now closed.

 At the Tree Trunk Scale

Both types of anisotropy, TIV and TIH, are also detected at the next target scale, approximately the size of a borehole radius, with the DSI Dipole Shear Sonic Imager tool.  At this scale, the most common evidence for TIV layering anisotropy comes from different P-wave velocities measured in vertical and highly deviated or horizontal wells in the same formation  -faster horizontally than vertically. But the same can be said for S-wave velocities. For years, whenever discrepancies appeared between sonic velocities logged in vertical and deviated sections, log interpreters sought explanations in tool failure or logging conditions. Now that anisotropy is better understood, the discrepancies can be viewed as additional petrophysics information. Log interpreters expect anisotropy and look for correlation between elastic anisotropy and anisotropy of other log measurements, such as resistivity.

Fracture- or stress-, induced elastic anisotropy has also been detected by sonic logs through shear-wave splitting. In formations with TIH anisotropy, shear waves generated by transmitters on the DSI tool split into fast and slow polarizations. The fast shear waves arrive at the receiver array before the slow shear waves. Also, the amount of shear wave energy arriving at the receivers varies with tool azimuth as the tool moves up the borehole, rotating on its way.

Detecting anisotropy in DSI waveform data is easy, but using the data to compute the orientations of the split shear waves is a bit trickier. If travel time and arrival energy could be measured for every azimuth at every depth, the problem would be solved, but that would require a stationary measurement. Logging at 1800 ft/hour [ 550 m / hr] , the DSI tool fires its shear sonic pulse alternately from two perpendicular transmitters to an array of similiarly oriented receivers, and the pulse splits into two polarizations. As the tool moves up the borehole, four components -from two transmitters to each of two receivers - of the shear wavefield are recorded. The four components measured at every level, along with a sonde orientation from a GPIT General Purpose Inclinometer Tool measurement , can be manipulated to simulate the data that would have been acquired in a stationary measurement. These data determine the fast and slow  directions, but cannot distinguish between the two. Including the travel-time difference information allows identification of the fast shear-wave polarization direction, which in turn is the orientation of aligned cracks, fractures or the maximum horizontal stress. 

In an example from a well operated by Texaco, Inc. in California , the fast shear-wave polarization direction obtained from such DSI measurements corresponds to fracture azimuths extracted from an FMI fullbore formation Microimager image. 

Amoco exploration and Production used information about shear velocities to optimize hydraulic fracture design in the Hugoton field of Kansas, USA. A key parameter for hydraulic fracture design is closure stress. Closure stress is related through rock mechanics models to Poisson's ratio, which is a function of the P- and S-wave velocities.

Thursday, December 6, 2018

Matrix Treatment in Alberta

This case concerns a Suncor Inc. operated gas well, Pine Creek 10-1, in Alberta, Canada. It has a 2493-ft (760-m) horizontal section, drilled through the carbonate reservoir above the water leg to a measured depth of 14,935 ft [4552 m].

Unlike the usual situation, the best porosity of the horizontal section was believed to be at the toe of the well rather than the heel. However, it was also believed that these high-potential zones had been invaded by drilling mud filtrate.To enhance productivity, it was important to ensure that the acid was pumped into the toe of the well to open up fractures and allow the mud to flow out.

To create the required diversion, it was decided to pump a Foam treatment. Foam is pumped into the formation, blocking further entry of the acid and diverting it to unstimulated reservoir. To minimize friction when pumping at the necessary rate, 2 inch coiled tubing was used to deliver the fluids. The relatively large CT diameter also helped avoid lock-up when running into the long horizontal section and offered more pulling potential if the string had become stuck. 

The downhole assembly consisted of a nozzle, two memory gauges separated by a knuckle joint, and a check valve. The knuckle joint added flexibility to an otherwise stiff assembly. Data collected by the gauges were used after the job to analyze the buildup and breakdown of the formation as successive diversion and acid phases were pumped.

A number of factors complicated the choice of acid additives - which is crucial to the success of any matrix treatment. First, as already noted, Suncor suspected that the formation had been invaded by significant quantities of mud filtrate, which contained a strong emulsifier likely to form an emulsion with spent acid. Second, the presence of 25% hydrogen sulfide [ H2S] in the well necessitated the use of corrosion-control additives that may react with other chemicals in the fluid.

 Consequently, extensive compatibility tests were run between the mud and proposed acid systems. The final treatment design included a number of stages:

  • tubing pickle, which is used to clean up the inside of the coiled tubing - 15% hydrochloric acid [HCl] , inhibitor and surfactant. 
  • preflush, to thin the mud in the wellbore - fracturing oil, antisludge agent and nitrogen, creating a foam with a quality of 50%.
  • Mudclean OB solution, to flush out any remaining mud in the well and water-wet the formation  prior to the FoamMAT job - water, surfactant and solvent as a foam of 50% quality.
  • diversion stages - water and surfactant with nitrogen as a 65% quality foam.
  • Squeeze acid - 15% HCl, with inhibitor, surfactant, de-emulsifier, antisludge agent, miscible solvent and H2S scavenger. The total volume of the acid, some 33,025 gal, was determined by a rule of thumb and past experience of a FoamMAT job carried out on a nearby oil well.
  • postjob flush - fracturing oil and nitrogen. Having pickled the CT and negotiated some problems running in hole caused by a hydrate plug, the preflush was pumped with the CT on bottom- at the end of the toe. Once all the preflush had been displaced across the open hole, the well was shut in for about 15 minutes to allow it to soak and then flowed back to recover any mud filtrate. Next the mudclean OB stage was pumped downhole and displaced using nitrogen. The well was then allowed to flow to clean up and another stage was pumped.
 When this had been displaced out of the well, the main treatment commenced. A series of 15 alternating acid - 1585 gal- and diverter 400 gal -stages were pumped at 25 to 80 gal/min. At the same time , the coiled tubing was gradually pulled out of the hole at about 10 ft/ min from the toe to the heel of the well. After pumping a diverter stage, the pumps were shut down for 10 minutes before the next acid was pumped. 

Midway through the job, the well went on a vacuum. To maintain a positive surface pressure and gain maximum information about the treatment, it was necessary to reduce the bottomhole hydrostatic pressure. The foam qualities of the two fluids were adjusted so that the diverter was 70% and the acid 25%. 

Surface pressure was plotted throughout the job to assess the success of the diversion stages. Once all the acid was pumped, the CT was run back to the toe of the well and postjob flush was pumped to break up the foam in the wellbore and hasten the cleanup.

The well was opened up to flow with the gauges still on bottom. During cleanup, the well flowed spent acid and estimated 21,000 gal of mud filtrate. Suncor believes that this mud came out of the natural fractures of the formation. Once the well was cleaned up, the well pressure and temperature were logged using the memory gauges.

The well is currently waiting to be brought into the production, but Suncor estimates that the acid treatment reduced the pressure drop across the reservoir by 435 to 725 psi. By comparing this to pretreatment pressure and rate information, additional gas deliverability due to the treatment is likely to be 2 to 6 million scf/D.

Wednesday, December 5, 2018

CT Logging and Perforation in Alaska

Coiled tubing logging located zones offering potential additional production that were perforated using CT-deployed guns.

 So far, ARCO's sector of the Prudhoe Bay has run 12 coiled tubing logging jobs in eight highly deviated or horizontal wells. The aims of these jobs were to obtain the production profile and verify the presence of channels using pulsed neutron logs. Where necessary, coiled tubing-deployed perforating guns were used to open up potentially productive zones. 

Well 15-07A exemplifies the job performed in Alaska. It is a virtually horizontal well completed with a 4 1/2 inch slotted liner at a total vertical depth of 8761 ft and a measured depth of 13,545 ft.

 Drilled as a sidetrack to a much older well and completed earlier this year (April 1994), the well was found to be producing lower rates of oil at a much higher gas-oil ratio (GOR) than was anticipated. Coiled tubing logging was used to determine the source of the gas production, to identify any nonproductive intervals and to tie in with previous logs using gamma ray, casing-collar locator and temperature logs.

Gas entry was located using the temperature log. Then, using pulsed neutron logs in conjuction with borax injection, the gas-oil contact was located and a possible channel behind the 7-inch liner indicated. 

Finally, CT was employed to perforate the 7-inch liner to contact potentially bypassed intervals. Some 20 ft of 2 1/8 inch guns were run in hole and detonated using a hydraulic firing head. Depth was correlated using a tubing-end locator. 

The CT perforation used a new pressure-activated firing head. It allows circulation and reverse circulation before and after firing the guns. An operating piston is attached to a sleeve that locks the firing pin in place. When sufficient differential pressure is established across this piston to sever the shear pins that hold it in place, the firing pin is driven into the detonator by the pressure.  

To establish this differential pressure, a ball is pumped down the tubing to form a pressure seal in the head. The ball diverts pressure to the underside of the operating piston, building up the pressure that severs the shear pins an detonates the guns. Up to twelve 500-psi shear pins can be incorporated into the head.

A key advantage of coiled tubing is its higher tensile strength than wireline. So, when it comes to perforation, there is no practical weight limit to the number of guns that can be run. The main constraint on gun length is the height of the lubricator. However, the downhole safety valve may be closed and successive sections of guns run into the well and connected together. 

Sunday, December 2, 2018

Logging and Perforating with Coiled Tubing

Like CT drilling , coiled tubbing logging has come of age only in the 1990s. One of its key selling points revolves around the stiffness of the tubing, enabling penetration into horizontal and high-angle sections. Additionally, wireline inside coiled tubing offers the potential to pump fluids downhole and log at the same time.

Successful application of CT logging requires the reliable interface of the coiled tubing and logging units. Wireline log acquisition systems are driven by depth. To supply real-time depth data for CT logging, an encoder relays a depth signal from the injector head into the logging unit through a dedicated interface. This depth information is also used by the monitoring system that records coiled tubing and pumping parameters. 

A newly designed coiled tubing head is now available to attach the logging tools to the CT. The modular head secures the cable in place, allows fluid to be circulated through a dual flapper valve during logging, and provides for electrical connection and mechanical release.

Fundamentally, a CT logging operation is not much different from its wireline counterpart. However, the tubing is stiffer than wireline so it tends not to stretch as much, and the injector head provides a stable speed. Coiled tubing may deploy most logging tools, as long as they are slim enough to fit inside the wellbore. The scope of slimhole logging -whether the wells were drilled using CT drilling or conventional techniques - has been limited by the availability of slimhole hardware. Now that scope is broadening.

Originally, slimhole logging tools were developed to gather petrophysical information in deep, usually hot, wells that required extra strings of casing, thereby reducing the final well diameter. Alternatively, they were needed to log through drillpipe under difficult hole conditions. These rigorous environments ensured that such tools were of necessity simple, reliable and rugged.

Today, CT drilling and slimhole wells are being used, or contemplated, for a broader  range of well types that have more sophisticated needs. To meet these needs, many standard and new high-technology imaging tools have been reengineered to perate in more restricted boreholes. For example, the DLL Dual Laterolog Resistivity tool and the combinable Litho-Density tool have been repackaged with diameters of 2 3/4 inch and 3 1/2 inch, respectively.

In addition, new instruments have been designed , such as the SRFT Slimhole Repeat Formation Tester tool for sampling the formation, the sourceless RST Reservoir Saturation Tool , and the Pivot Gun for slimhole perforation. Combinability of tools and coiled tubing logging capability are standard features.

To date, coiled tubing is most often used for production logging, sometimes combined with CT-conveyed perforation. As usual, the production logging tool string measures a range of parameters, including spinner revolution, fluid density, pressure and temperature; a gamma ray tool and a casing-collar locator are also included.

Production logging of high-angle or horizontal wells presents a tremendeous challenge. For example, there may be stationary fluid  stationary fluid, back-or cross flow - some zones may be accepting fluid produced by other zones. Only a fraction of the fluids "seen" by the tools may actually be moving. To overcome these difficulties, the production logging program must be sufficiently flexible to respond to changes in well behavior.A typical CT production logging job involves the following steps: 
  • Rig up and pressure test equipment.
  • Run in hole stopping to check CT weight.
  • Correlate depth with a reference log using casing-collar correlation and gamma ray logs -vital because the CT tends to form a helix in the well.
  • Log the well while shut in.
  • Log in both directions with typically four passes at say, 40,60,80 and 100 ft/min.
  • Observe well anomalies, making some stationary log measurements to look for backflow.
  • Pull out of hole.
 Another production-related CT logging service employs pulsed neutron logs and borax solution. The borax is pumped into the CT-production tubing annulus at a pressure above that of of the reservoir but below the fracturing pressure. Because borax is more effective than reservoir fluid at slowing neutrons, pulsed neutron logs can trace where it has gone and hence confirm the location of a suspected channel and indicate high-permebility zones. With additional openhole log data, initial reservoir saturation information may also be derived. 

After the production profile of a well and potential hydrocarbon saturated zones have been identified, reperforation using CT-conveyed guns may be necessary.

Matrix Treatment

The most traditional of all coiled tubing services is the delivery of fluids downhole. No account of the practical uses of coiled tubing would be complete without describing at least one pumping application - a role that has become more important with the proliferation of horizontal wells.
  As in other areas, increasingly sophisticated pumping services are available. For example, a relatively new matrix treatment tackles an old problem, diversion. Unless a stimulation fluid is successfully diverted into the areas that most need it, the fluid will channel into the high-porosity, high-permeability formation that least requires improvement. Horizontal wells generally have a much longer reservoir section than their vertical counterparts, so the problem of diversion is proportionally more difficult. To compound this, few horizontal wells are completed in a way that allows reven rudimentary zonal isolation.
  Traditionally, diverting materials - like calcium carbonate or rock salt - are introduced to temporarily plug the zones of the formation taking most fluid, redirecting flow to more needy parts of the wellbore. But the plugging must be reversible- by dissolution in acid or reservoir fluids- and leave the formation undamaged. Not an easy criterion to meet. 

A successful alternative employs stable foam that is generated in the "thief zones"   as a diverter. Alternating stages of acid and the foam - made from water containing surfactant and nitrogen are pumped. The diverter enters the formation that is taking fluid. Some 10 minutes or so are allowed for the foam to build up and, when pumping restarts with a new acid stage , a pressure increase is seen at surface as the foam ensures the acid enters some other part of the formation. Pressure gradually decreases until it is time to pump the next foam stage. Once production starts, the foam breaks down and flows out of the well leaving undamaged, acidized formation.

Coiled tubing is an ideal way of targeting the delivery of the treatment fluids to the formation, particulary in horizontal wells. Furthermore, because the volume inside CT is relatively small, a flexible treatment program may be employed, based on pressure responses observed during pumping.

Friday, November 2, 2018

Coiled Tubing Takes Center Stage

When it comes to coiled tubing, there can be few doubters left. What was once a fringe service has moved to center stage in the oilfield theater of operations. 

For many years, coiled tubing (CT) operations occupied the twilight zone of a fringe service offering niche solutions to specialized problems. However, over the past five years, technological developments, improved service reliability, gradually increasing tubing diameter and an ever growing need to drive down industry costs have combined to dramatically expand the uses of coiled tubing.

Today for example, coiled tubing drills slimhole wells, deploys reeled completions, logs high-angle boreholes and delivers sophisticated treatment fluid downhole. This article will look at the technical challenges presented by these services and discuss how they have been overcome in the field. 

 Drilling Slimhole Wells

Slimhole wells - generally those with a final diameter of 5 inches or less - have the potential to deliver cost-effective solutions to many financial and environmental problems, cutting the amount of consumables needed to complete a well and producing less waste. Other benefits depend on what kind of rig drills the well. Compared to conventional rigs, purpose-designed smaller rotary rigs can deliver slimhole wells using fewer people on a much smaller drillsite, which cuts the cost of site preparation and significantly reduces the environmental impact of onshore drilling.

Coiled tubing drilling combines the virtues of a small rig with some unique operational advantages, including the capability to run the slim coiled tubing drillstring through existing completions to drill new sections below. There is also the opportunity to harness a coiled tubing unit's built-in well control equipment to improve safety when drilling potential high-pressure gas zones. This allows safe underbalanced drilling- when the well may flow during drilling.

Although there were attempts at CT drilling in the mid-1970s, technological advances were needed to make it viable. These include the development of larger diameter, high-strength, reliable tubing, and the introduction of smaller diameter positive displacement downhole motors, orienting tools, surveying systems and fixed cutter bits. Furthermore, currently available coiled tubing engineering software enables important parameters to be predicted, such as lock up -when tubing buckling halts drilling progress- available weight on bit, expected pump pressure, wellbore hydraulics and wellbore cleaning capability.

Through-tubing reentry in underbalanced conditions is a category of CT drilling that may grow significantly. Reentering wells without pulling the production string is a cost-effective way of sidetracking or deepening existing well.

The development of through-tubing, reentry underbalanced drilling is of great interest in the Prudhoe Bay field on the North Slope of Alaska, USA, where operator ARCO Alaska Inc. has an alliance with Dowell to develop coiled tubing technology. The alliance has already scored a number of technical and commercial successes. For example, a 600-ft horizontal section extended using underbalanced CT drilling, resulted in production three times greater than predicted rates.

As with any mature operation, there is a need to extend field life and gain incremental reserves at a cost that reflects today's oil price. While the primary aim is to devise a strategy for for low-cost well redevelopment, a secondary aim is to improve the productivity of horizontal wells by reducing formation damage associated with conventional overbalanced drilling.

In line with these objectives, candidate wells for CT drilling are divided into two classes: 
  • the replacement of waterflood wellbores that have corroded because of the high carbon dioxide content of the water.
  • horizontal sidetracks to replace conventional gravity drain wells, tapping new zones and improving recovery. 
Four years ago, ARCO began sidetracking the existing wells using conventional Artctic rigs. The corroded tubing was pulled and new well sections drilled. ARCO realized that this was going to be a necessary procedure for the future, but that conventional tecnology was going to incur considerable cost. Using a traditional Arctic rig to enter a Prudhoe Bay well, drill the sidetrack and  run a completion costs over $1 million -as many as 800 sidetracks may be needed in ARCO Prodhoe Bay unit.

The goal of the Arco-Dowell alliance is to develop a lower cost alternative to conventional rig sidetracks. To date, promising results show that CT sidetracks can ultimately be performed at half the cost of rig operations. 

The second objective of improving productivity employs underbalanced drilling drilling in new, low permeability zones. Underbalanced drilling offers the opportunity to minimize formation damage incurred during drilling and to optimize the productivity of the completion. As the first case study shows, the technique does seem to offer some benefits.

Underbalanced drilling sometimes helpps alleviate other problems like differential sticking. Oil production during drilling helps the string slide better and aids hole cleaning by carrying cuttings to surface more effectively. 

Drilling and directional control equipment for through-tubing CT drilling is largely proven, although systems require continued refinement and improvement. As higher build rates are achieved, slimmer CT directional tools may be necessary to accomodate through-tubing operations in some existing wells. 

Bit selection must match the geology, motor spesifications and the maximum allowable pumping pressure, while at the same time offer viable rates of penetration with less weight on bit and  higher rotation speeds than is normal. Polycrystalline diamond compact (PDC) bits are commonly used in medium-to-soft formations, and thermally stable diamond or natural diamond bits for harder formations.

A positive displacement mud motor is used to rotate the bit. Most CT drilling is performed using motors with a diameter less than 3 1/2 in, such as Anadrill's 2 7/8-inch steerable motor.

For directional control, dowell uses an orienting tool operated by mud-pump flow rate to alter the tool face. Anadrill's SLIM 1 MWD system coupled with a gamma ray log is used to monitor the wellbore's progress through the formation in real time. Data are transmitted to surface using conventional mud-pulse technique.

There are systems available that use wireline inside the coiled tubing. These can transmit directional data to surface at a higher rate than mud-pulse tools and hold the potential to provide electrical power to activate downhole tools. However, installation and maintenance of the cable increase drilling costs.

In case the bottomhole assembly gets stuck, a hydraulic or shear release tool allows the coiled tubing string to be disconnected and recovered in one piece. A flapper valve just above the disconnection point prevents any wellbore pressure from entering the CT string.

It would, however, be wrong to say that all the mechanical challenges of drilling have been met. For example, transmitting sufficient weight to the bit can be problematic. Since it is impossible to rotate the CT from surface, it is often difficult to overcome axial friction along the length of the CT, particulary in deviated wells. Because of this, the weight applied at surface frequently becomes "stacked up" against the borehole wall instead of reaching the bit. This phenomenon is well known for slide drilling, but is exacerbated by the flexibility of the CT and increases with the sidetrack angle.

Numerous solutions have been proposed, including hydraulically activated "crawlers" that grip the borehole wall and pull the CT into the hole, and hydraulic thrusters that apply weight by pushing on a slip joint or piston just above the bit. 

A conventional kick-off technique uses a whipstock plug- a log, inverted steel wedge that is set in the wellbore and diverts the drillstring toward the side of the hole to initiate a sidetrack. To achieve this through tubing on Prudhoe Bay wells requires a whipstock that will pass through 3 3/4 inch minimum restriction inside the tubing but sit firmly and reliably inside the casing below that has an inside diameter of more than 6 inch, so far this has proved difficult to achieve. 

Development of CT drilling is not exclusive to Alaska. For example, in the North Sea, the Danish Underground Consortium is turning to the technique as an alternative to its pioneering strategy based on long, conventionally drilled horizontal sections completed so that many individual zones may be separately fractured. Because these stimulation treatments and all the associated hardware can be expensive, operator Maersk Olie og Gas believes that a network of slimhole wells drilled quickly and underbalanced with coiled tubing may be more cost-effective. 

To evaluate this development strategy, Dowell and Anadrill drilled the first successful CT drilling offshore development well in the North Sea. The well was completed in May 1994 on Maersk's Gorm platform and initially produced some 3000 BOPD - up to four times the anticipated level. 

To date, CT drilling has not been used as a major exploration drilling tool. One factor that limits its usefulness for exploration drilling is the maximum openhole diameter possible. This is increasing as larger diameter coiled tubing becomes available. With 2 3/8-inch tubing, a vertical open hole of up to 8 1/2 inch may be drilled. Because it is stiffer and can extend farther before lock up, larger diameter CT also allows longer horizontal sections to be drilled. However, horizontal drilling necessitates more trips into the well and more cycling of the CT over the gooseneck.

Thursday, November 1, 2018

Inversion for Reservoir Characterization

Fundamental to reservoir characterization is assigning physical property values everywhere within the reservoir volume. The challenge of using all available data to choose the best assignment is being addressed by a group of scientist. Available data could include seismic data, log data, well test results, knowledge of the of the statistical distributions of the sizes and orientations of sedimentary bodies, and even spesific information about reservoir geometry. 

To incorporate all these diverse sources of information, the scientists use an inversion method that begins by considering all possible assignments. Each assignment is represented by a single point in a multidimensional space that has as many dimensions as there are cells in the reservoir model. In assigning acoustic impedance in a reservoir model comprising 10 x 10 x 10 discrete cell, for example, each assignment would be represented by a unique point in a 1000 dimensional space. 

 The available data are then used to determine which of these points are acceptable. This is achieved by representing each available data set -3D surface seismic data, well data, or whatever -by a cloud of points corresponding to assignments that fit that particular data set. Finding an acceptable assignment then reduces to finding a point that lies at the intersection of all such clouds of points.

As the solution is always nonunique ( more than one assignment satifies all the available information), this intersection set will not be a single point but have some volume in the multidimensional space. A procedure to choose a single, best assignment is therefore required. The current method starts with an initial guess and then modifies it as little as possible until the intersection set is reached.

A synthetic example illustrates the method. First, a reservoir model is constructed 21 x 21 horizontal cells and 201 vertical cells, with an acoustic impedance value assigned to each cell. This synthetic model is equivalent to a volume of about 1 km x 1 km horizontally and 100 milliseconds. From this are generated two data sets that would be measured if the reservoir were real: first, a log of acoustic impedance in a well through the center of the model; second, the surface seismic response, which displays a lower spatial resolution than the original model. 

The challenge is to reconstruct the original acoustic impedance model using the log and seismic data only. A reasonable starting model can be obtained from a simple extrapolation of the well log data. This clearly fails to reproduce structural variations away from the well that appear in the original model. However, modifications to this first guess using in addition the surface seismic data produces a reconstruction that is much closer. 

Monday, October 22, 2018

Obtaining Reservoir Engineering Parameters in Each Layer

Once the reservoir geometry has been defined, if not actually computed, one step remains before synthesizing the complete reservoir model. This is the estimation of key reservoir engineering parameters in each defined interval across the areal extent of the reservoir. Key parameters are net thickness, porosity, oil, gas and water saturations, and horizontal and vertical permeabilities. The computation proceeds in two stages. 

First, in each well the parameters must be averaged for each interval from the petrophysical interpretations.  This is performed in the component property module and relies on careful selection of cutoffs to exclude sections of formation that do not contribute to fluid movement. Choice of cutoffs is made with the help of sensitivity plots showing how the averaged parameter varies with cutoff value, and preferably in a well with well-test data to validate the cutoff choices. 

Second, the averaged parameters for each interval must be gridded or mapped across the reservoir. In the log property mapping module, the RM package brings into play powerful algorthms that use seismic data to guide the mapping. The key to the method is establishing a relationship at the wells between some attribute of the seismic data and a combination of the averaged well parameters, and then using the relationship to interpolate the averaged parameter everyhwere in the reservoir. The seismic attribute could be amplitude, or acoustic impedance calculated earlier using the inversion module, or one of several attributes that are routinely calculated on seismic interpretation workstations and the imported to the RM system, or simply depth.

The relationship may be linear - that is, the combination of averaged parameters is defined as a simple weighted sum of seismic attributes -or nonlinear, in which an elaborate neural network approach juggles several linear relationships at the same time, picking the best one for given input. Linear relationships easily handle smooth dependecies such as between acoustic impedance and porosity. The nonlinear approach is required for averaged parameters, such as saturations, that may vary abruptly across a field.

In practice, the log property mapping module guides the interpreter through the essential stages: choosing the interval to map, comparing seismic data at the well intersections with the averaged well data, establishing relationship that show a good degree of correlation and then proceeding with the mapping. The advantage of log property mapping over conventional mapping was demonstrated in both the Conoco Indonesia, Inc. and Pertamina Sumbagut case studies. Research continues into finding ways of using all available data to assist the mapping of log data across the reservoir.

Building the Reservoir Model and Estimating Reserves

The stage is set for the RM package- the Model Builder. This module fully characterizes the reservoir by integrating the geometric interpretation  established with the correlation and section modeling modules, including definitions of reservoir tanks and fluid levels, with the reservoir engineering parameters established using the component property and log property mapping modules.

 The main task is constructing the exact shape of the reservoir layers. This is achieved by starting at a bottom reference horizon and building up younger layers according to their assigned descriptors, mimicking the actual process of deposition and erosion. For example, if a layer top has been defined as sequential and conformable, it will be constructed roughly parallel to the layer's bottom horizon. If a reference horizon has been described as an unconformity, then underlying layers can approach it at any angle, while layers above can be constrained to track roughly parallel. 

The areal bounds on layers are determined within the model builder module by severeal factors. First, spesific geometries can be imported. Second, areal bounds may be implied through the geometries created with the section modeling module. Third, the contours of petrophysical parameters estabished during log property mapping can establish areal limits. Fourth, thickness maps of layers can be interactively created and edited prior to model building.

The key dividen of model building is the establishment of reserve estimates for each tank. Oil in place, total pore volume, netpay pore volume, water volume, reservoir bulk volume, net-pay area and net-pay bulk thickness are some of parameters that can be calculated and tabulated on the workstation. Conoco Indonesia Inc.'s estimates using the RM package were in close agreement with standard calculation procedures. During appraisal, when the oil company decides whether to proceed to development, establishing reserve estimates is crucial. As a result, the many steps leading to this moment will be reexamined and almost certainly rerun to assess different assumptions about the reservoir. 

Say, for example, a geologist is working on correlating logs and creating geologic tops, while the geophysicist is preparing an inversion to obtain acoustic impedance. If both want to work concurrently, the version manager simply grows two branches. 

Similiarly, a reservoir engineer may wish to try several scenarios for mapping the distribution of porosity within a layer-say by mapping well log values only and alternatively by using seismics to guide the mapping with the log property mapping module. Two versions can be made in parallel with a branch for each scenario. Several further steps along each interpretation path may be necessary before it becomes clear which mapping technique is better. 

Material Balance Analysis and Preparation for Simulation

For reservoir managers striving to improve the performance of developed fields - for example, investigating placement of new wells or reconfiguring existing producers and injectors to improve drainage- the RM package has two more modules to offer. One provides a sophisticated material balance analysis that assesses whether the established reservoir model is compatible with historical production data.  The second converts the reservoir model into a format suitable for simulating reservoir behavior and predicting future production.

 Material balance analysis is performed using Formation reservoir test system module. In traditional material balance analysis, reservoir volume is estimated by noting how reservoir pressure decreases as fluids are produced. The more fluids produced, the greater the expected pressure decrease. Exactly how much depends on the compressibility of the fluids, which ban be determined experimentally from down-hole samples through pressure-volume-temperature (PVT) analysis, the compressibility of the rock, which can be determined from core samples in the lab, and , of course, reservoir volume. Faster declines in pressure than expected from such an analysis might indicate a smaller reservoir than first thought. Slower declines might indicate a high-volume aquifer driving production, or less rarely, connected and as yet undiscovered extensions to the reservoir. This traditional anaysis of reservoir size and drive mechanism requires no a priori knowledge of reservoir geometry, only production, pressure and PVT data. 

The module uses these basic principles of material balance, but applies them within the geometrically defined reservoir tanks of established reservoir model. This allows not only verification of tank volumes, but also estimation of fluid communication between tanks. Communication between tanks could be due to an intervening low-permeability bed or a fault being only partially sealing. Another result is the prediction of how fluid contacts are moving.