ABSTRACT

CL Consultants Limited has been involved in over seventy horizontal wells in S.E. Saskatchewan. From this experience has arisen a number of observations as to the tools and skills needed in "Geo-steering" a horizontal well and the assessment of reservoir quality. The mandate of the wellsite geologist is to find, place and maintain the wellbore in a location deemed as optimum. Using a continuous flow of information from sample analysis, hydrocarbon detection, penetration rate, survey data, and LWD tools, the wellsite geologist must assimilate all the data to make appropriate decisions on well path. How the geologist in the field uses this information to steer the bit to and within the reservoir and draw conclusions as to reservoir quality will be discussed.

INTRODUCTION

In 1989 CL Consultants was contracted to provide the Hydrocarbon Logging and the Wellsite geologist for a well in central Alberta. This project was to drill the Nisku horizontally. The depth of the zone was clearly outlined and a predetermined depth to go horizontally was defined. Using the hydrocarbon mud logging equipment, in particular the chromatograph, an oil contact was identified. Once this contact was reached it was clear what depth had to be maintained in the horizontal leg. The well proved to be very successful and upon completion of the job many observations were made and many questions where raised. Correlation of the samples, and the hydrocarbon data to the wireline data was very concise. Porosity and reservoir quality could be defined while drilling. This, combined with the ability to steer the bit into the best reservoir, made the proposition of horizontal drilling very exciting.

Today, the skills, tools and knowledge have greatly increased. With this expansion in techniques, the responsibilities of the wellsite geologist have changed and expanded. On a typical vertical well one geologist is responsible for tracking the wellbore as it drills through the various strata to a generally predetermined total depth. Samples, penetration rate and hydrocarbon detection provide many clues to what is occurring down hole. Once the primary objective is drilled the Geologist reports observations on porosity, fluorescence, and other hydrocarbon evidence. The zone is then logged and all the information compiled and evaluated for hydrocarbon potential. Reservoir quality is based primarily on the open hole logs.

The role of the geologist in a horizontal application creates an entirely different operational situation on the location. The process starts with the project geologist interpreting what is the most optimum location for the wellbore in the reservoir. Prior to drilling, this "best spot" is outlined to the wellsite geologist in the form of a window that must be maintained. Once the wellsite geologist is on location the build section is logged and the over lying strata is correlated to the regional geology. Any change in the build section that is deemed necessary, due to changes in tops observed in the above strata, are discussed with the project geologist. Once the reservoir is encountered the target window is set and maintained. Any further change in lithology will result in a change of the wellbore trajectory.

Changes in the well path are time consuming, costly and ultimately may affect ease of completion. Therefore, determining if a change is necessary has to be done accurately. The first indication of change is most often seen as a decrease in the rate of penetration, followed by a resulting drop in total gas on the Hydrocarbon detector. The wellsite geologist must be aware of this change and look at the samples to make a further determination on what has occurred. The surveys become very important, as they will indicate if the well bore unexpectedly changed direction, or if the strata has changed. For example, if the angle did not change and cap rock appears in the sample then one can assume that the porosity cap interface is descending. The bit must be oriented down to a new lower TVD window to expose the best reservoir. The directional driller must be notified immediately to execute a new orientation in order to limit the loss of horizontal section.

The ability to steer and reach the optimum position in the reservoir, means that you need personnel monitoring the well twenty four hours a day. Every survey, sample, and reading must be checked immediately, so the wellbore is in the best reservoir. If the path of the well bore is good, then the monitoring of any changes becomes the geologists primary job. If the reservoir looks poor a change in well path must be made. The determination of reservoir quality based on all the different pieces of information available will dictate the action to be taken. The information the wellsite geologist has for horizontal wells is virtually identical to that attained in vertical wells, however the effect of his conclusions are felt immediately. All findings must be concisely communicated to the geologist in the office and all drilling personnel on location.

HORIZONTAL DRILLING IN SASKATCHEWAN

In S.E. Saskatchewan the bulk of the proven crude oil reserves in the Williston Basin are produced from Mississippian sediments. The majority of new oil is produced by enhanced recovery methods through the application of horizontal drilling. In today's markets, companies must maintain cost effective drilling programs to remain competitive. The added cost of horizontal drilling, leads companies to search for ways to cut drilling costs in these wells. An example of one successful major cost cutting practice, is to drill with clear water until intersecting the top of the Red Beds, then mud up while drilling the Red Beds, ensuring a good mud system is in place prior to intersecting the Mississippian Cap Rock. This has dramatically decreased the overall number of days needed to drill a horizontal well. Additionally, the deletion of open hole logging programs and of a reamer trip through the build section prior to setting intermediate casing, has also lowered well costs. These cost saving measures have given the wellsite geologist greater responsibility to find and follow the porosity within the producing formation while making a continuous accurate observation of reservoir quality.

In Southeast Saskatchewan, the wellsite geologist most commonly has three basic tools to interpret and direct the well path. These tools are:

• 1) Drill Cuttings analysis.
• 2) Rate of Penetration.
• 3) Total Hydrocarbon Detection.

To successfully drill a horizontal well and optimize reservoir exposure, certain elements of the process have to be clearly outlined and carefully executed. The process starts with the wellsite geologist being introduced to the project through a discussion with the project Geologist who clearly outlines the well plan. The wellsite geologist then utilizes sample data, hydrocarbon data, penetration rate, and any logging while drilling (LWD) tools he has to execute this plan and optimize the well. This paper will discuss Well Planning, and the role of; Total Gas detection, Chromatography, Rate of Penetration, and LWD tools in determining reservoir quality, and the importance of communication in the drilling of horizontal wells.

WELL PLANNING

Good well planning can make the difference between a marginal well in which drilling costs are recovered, and a successful well which can have a longer economically viable production life. Two basic methods in planning a well have been developed.

• 1) Drilling a well from A to B at a predetermined subsea elevation, regardless of any changes in lithology and visual oil shows observed while drilling. No attempts to follow the porosity cap rock interface would be made, unexpected changes in the formation are not reacted upon to try to stay on the optimal zone and valuable horizontal well bore could be wasted. This method of "TVD" drilling, leaves the wellsite geologist with a minimum of responsibility. Gamma, total gas detection and chromatography are not necessarily required, and survey data is used to maintain the predetermined trajectory. This method does not allow for undulations and variations of the lithologies within the pay zone and lower reservoir quality can be expected. However, the TVD drilling method may be useful for drilling in other areas and strata, such as reef deposits, where the oil/gas and the oil/water contacts are known.
• 2) The method of a predetermined window with the ability to change angle and move within the formation to try and stay in the best reservoir is an alternate choice. Changes within the reservoir can be reacted upon to attempt to remain in the best production zone. In S.E. Saskatchewan generally a true vertical depth known as the "Hard Floor Depth" (usually based on estimates as to the location of oil/water contact) is designated as the lowest true vertical depth the wellbore will be allowed to travel, but above that point any variation in lithology can be monitored and change easily made.

The average length of a horizontal well in southeastern Saskatchewan is from 400 to 600 meters. If we estimate that we can produce oil from a quarter section of reservoir, this gives us a producing area of 640,000 square meters. If we assume a reservoir of 16% porosity with an estimated recovery of 25% of the oil in place, then every meter of net pay left above the well bore could result in a loss of 25,600 cubic meters of oil. The second method is more flexible and allows the geologist to follow irregularities within the pay zone, insuring that little or no reservoir will be left above the well bore.

A large part of well planning is based on the information the geologist has collected. In S.E. Saskatchewan, the mapping of the Mississippian unconformity is imperative for well planning. With the development of 3D seismic, mapping of the unconformity over these reservoirs has resulted in better well planning, but seismic can be costly and the smaller operators may not be able to conduct surveys of this magnitude. Seismic, though a highly developed science, still can only map the top of the unconformity leaving the location of the Mississippian Porosity below the cap rock to interpretation. However, given the density of vertical wells already drilled within these pools with available information obtained from open hole logs and recovered core, expensive seismic may not be needed to drill successful wells in these pools. With good well correlation and core analysis, perspective zones can be mapped and drilled with reasonable success.

RATE OF PENETRATION

Penetration rate is the only measurement that is instantaneously available to the wellsite geologist for analysis. Drill cuttings and gas detection are both delayed by the lag time, while the LWD tools and survey tools are located 12 to 15 meters behind the drill bit. In general, a change in the penetration rate may be the first indication of a formation change.

The penetration rate is predominantly affected by the porosity and permeability. Sediments with a high porosity and permeability tend to drill faster. Whereas dense sediments with lower porosity tend to have slower penetration rates. Basically this is due to the ratio of rock volume to open pore spaces within the rock. However, the wellsite geologist must be aware of the mud properties and drilling parameters that can also effect the penetration rate.

Low water loss and high suspended solids content in the drilling fluid cause slower penetration rates. If there is a high water loss, water is jetted into the formation in front of the bit increasing the formation pressure (spurt loss) lowering the hydraulic lift at the bit and increasing penetration rates. High solids content within the drilling mud tend to plug formation pores, decreasing spurt loss by not allowing the drilling fluid to enter the formation at the bit, which slows the penetration rate. For example, drilling fluid with a density of 1100 Kg/m3 and water losses of 12 to 14 will drill faster than drilling fluid with a density of 1100 Kg/m3 mud and fluid losses of 6 to 8, regardless of the inherent properties of the rock type being drilled.

One of the major difficulties in horizontal drilling is getting enough weight to the bit, particularly when orienting or steering the bit. The hole drag is caused by the friction between the drill pipe and the sides of the well bore in the horizontal section of the well. As a rule, the hole drag gets worse with increasing horizontal length and exhibits a proportional relationship to the length of horizontal section. Thus gradually making steering slower and more expensive until a point is reached where orienting is no longer feasible.

Rate of penetration in horizontal wells has the unique feature that drilling breaks can be mechanically produced. For example, when orienting the bit to change direction in the well path, the penetration rates tend to be noticeable slower. Then once the direction change is attained the rig can rotate the drill string again, increasing the penetration rate quite dramatically. This makes the identification of rotating and orienting on the strip logs imperative so false drilling breaks are not used as indications of lithology change.

HYDROCARBON DETECTION:

Hydrocarbon detection is most commonly performed by the use of a Total Hydrocarbon detector. This tool continuously measures the amount of all combustible hydrocarbons, carried up the well bore by the drilling fluid, that is released at surface. The correlation of the total gas readings to the depth of origin is the responsibility of the wellsite personnel. Once this correlation (calculation of lag time) is made, conclusions can be drawn as to the relative amount of hydrocarbons present within the rock, and estimates of porosity and reservoir quality can be made. Further mud gas analysis can be made by the use of chromatography, which separates and measures the constituent members (commonly methane, ethane, propane and butane) within the mud gas. With the chromatographic mud gas data, Alkane Ratio plots may be constructed and estimates can be made as to the type of fluid (gas, oil, or water) within the reservoir.

Gas detectors are essential in drilling horizontal wells as they can give early indications as to the quality of the reservoir being drilled. Within one lag time the hydrocarbon detector can identify which part of the reservoir produces the best hydrocarbon responses. Gas responses can give the wellsite geologist an early indication of formation change. Variations in penetration rate, permeability, mud density, and different rock characteristics will have varying effects on gas signatures. (See Table #1)

Changes in penetration rate will produce subsequent changes in the hydrocarbon responses. Any change in the penetration will yield a proportional change in gas readings regardless of reservoir potential. As an example, if the penetration rate is 6 minutes per meter and the background gas is 50 units, then an increase in the penetration rate to 3 minutes per meter will produce a background gas increase to 100 units. This does not indicate better reservoir, since an increase in drilling rate by a factor of two has simple resulted in a two fold increase in measured hydrocarbons by simply drilling twice as much rock volume over the same time interval.

Hydrostatic pressure also effects the hydrocarbon readings. If the hydrostatic pressure (HP) exceeds formation pressure (FP) the readings may be suppressed due to flushing of the hydrocarbons in front of the bit. The greater the permeability the more susceptible the formation may be to this flushing action. If HP is lower than FP, the hydrocarbons will enter the mud system from unknown points within the productive zone as produced gas, leading to elevated gas readings.

Even in a well balanced mud system, an increase in pressure at the bit, will cause a certain amount of flushing of the reservoir hydrocarbons. This is due to the mud column in the well bore changing from static pressure to dynamic pressure (Equivalent circulating pressure) at the bit. Dynamic pressure exceeds static pressure by an amount equal to the pump pressure and a flow friction coefficient. This action effects the formation close to the drill bit, causing a localized increase in dynamic pressure. It must be noted that the dynamic pressure will increase as the length of horizontal section increases due to an increase in surface area of the well bore and subdue oil shows. These factors make it imperative for the geologist to be aware of the hydrostatic pressure and the formation pressure as they effect correlation and identification of the hydrocarbon shows.

Viscosity of the drilling fluid can also suppress gas readings by inhibiting the breaking out of the formation gas from the mud at surface. The entrapment of the mud gas causes re-circulation of liberated formation gas within the drilling fluid. (See Table #2)

DRILL CUTTINGS

Being able to collect and communicate the interpreted sample data to the area geologist in a clear, concise manner is essential to the success of a horizontal well. In describing sample cuttings the use of Dunham's classification of limestones best conveys the description of carbonates being drilled. Dunham's classification describes the depositional texture of a carbonate and by using one of the carbonate rock types whether Mudstone to Grainstone allows a single word to convey a clear impression of porosity and permeability. (See Table #3)

Sample quality is a major concern in horizontal drilling. With the cuttings being circulated along the length of the well bore some degree of damage will occur due to rolling of the sample along the well bore and crushing of a portion of the sample by rotation and movement of the drill pipe. It must also be noted that sample quality usually deteriorates with the increase in horizontal length simply because the sample is in the well bore for a longer period of time. Such damage may result in cuttings from a very porous carbonate being crushed into a lime mud which destroys the rock fabric. Where the rock matrix is harder and less porous damage is not as severe. Drilling fluids with good hole cleaning properties will decrease the overall time the cuttings are subjected to this type of damage.

Careful sample preparation, is imperative to successful description and interpretation of the samples. Over heating the samples will tend to cook and destroy the residual hydrocarbons contained in the cuttings producing a dark brown fluorescence, or worse yet, no fluorescence under ultraviolet light. This could lead to difficulty in determining the hydrocarbon content and false interpretation of the potential production zone. The use of an air vacuum or heat lamp system in drying a sample would eliminate this problem.

COMMUNICATION

Communication between the project geologist, the wellsite geologist, and among all the other services on location is of paramount importance. The wellsite personnel generally are not as knowledgeable about the area and depend on being able to discuss the data collected and how it fits with the overall geology of that area with the project geologist. Good communication must also exist between the directional drilling company representatives and wellsite geologists. These are the individuals that will control the well bore to follow the preset subsea windows for the horizontal section and make adjustments to the proposal when necessary to optimize production.

Another very important aspect of communication that is critical is the ability to transmit strip logs and data to and from the location. It is crucial that all parties have the same information when a decision must be made.

EXAMPLE OF PATH DETERMINATION BY THE WELLSITE GEOLOGIST.

One well particularly exemplifies the interdependence of correlating samples, hydrocarbon detection and penetration rate to determine where the well path should be placed. The Mississippian unconformity was intersected at -620.3 meters subsea and is underlain by the Kisbey Dolomite which subcrops at -629.8 meters.

The Mississippian cap rock at this location is 9.5 meters thick and consists of dense anhydritic Dolomite. Samples, hydrocarbon data, and penetration rate all identified the cap. Upon entering the Kisbey member the penetration rate increased indicating better porosity, however samples and gas values did not indicate potential reservoir. After intersecting the Alida member at 1430m measured depth, the gas values increased, and samples showed good oil staining with penetration rates also indicating good porosity. The well bore was leveled off to follow the good reservoir. At 1511m measured depth the penetration rate started to slow down with gas values decreasing and samples lacking oil staining and fluorescence. By 1521m samples indicted we had penetrated Mississippian cap rock. The well bore had to be lowered to try to identify the Alida porosity again. The Alida member was again encountered at -636.2 meters subsea or 6.4 meters lower in structure than initially drilled. Penetration rates increased indicating the presence of good porosity, however samples at this depth showed a lack of the oil staining and fluorescence, that was previously encountered in the Alida at the higher structural elevation. The gas values through this lower interval were also not as high as previously measured. Based on the lack of fluorescence in the samples, and low mud gas values, this section of the Alida is believed to be water saturated and therefore below the oil/water contact.

The reservoir quality and characteristics as calculated by the wellsite geologist proved to be accurate and defined a much different picture of the reservoir than originally expected. If interpreted correctly penetration rate, samples and hydrocarbon data will give an accurate indication of reservoir quality while drilling.

DIFFERENT APPLICATIONS OF HORIZONTAL DRILLING

Most of the producing reservoirs in southeastern Saskatchewan are situated on the northeast rim of the Williston basin. This paleogeographic location has the producing formations dipping south to southwest toward basin center. The producing formations in this area consist of a bedded sequence of carbonates instead of one homogeneous unit that was eroded to produce an undulating Paleo-topography. These beds appear to have different water saturations and oil water contacts. In planning a horizontal well, the direction of the well can either be drilled along strike of these formations, opening up only one producing bed, or across the dip of the beds tending to access production from numerous beds which subcrop against the unconformity.

It is possible, that communication does not exist between the different members of the same formation. Therefore, if the sequence of formations, or different members of one formation, all subcrop in one well with sufficient thickness of reservoir in each of the zones, a horizontal well could be drilled with two or three different legs with each accessing different producing horizons.

If this theory is valid there is great potential for increased recovery of oil reserves from existing pools in southeastern Saskatchewan. The geology of this area is complex and not as straight forward as once believed. The application of horizontal drilling has allowed exploitation of different zones that could not be achieved through normal drilling practices.

CONCLUSION

Determination of reservoir quality can be made on wellsite. With this ability to assess reservoir quality and convey the results to the project geologist, changes in the well path can be executed and enhance reservoir production.

To achieve the best reservoir exposure it has become necessary to expand the role of the wellsite geologist to include the monitoring of all aspects of the drilling operation. Drilling parameters, mud properties, and surveys, in addition to his normal array of responsibilities (such as samples, penetration rate and hydrocarbon detection), must all be assimilated on an on going basis. Decisions based on the interpretations of the wellsite geologist can be felt immediately, and the importance of accurate findings have never been more paramount.

ACKNOWLEDGMENTS

CL Consultants wishes to thank Talisman Energy for their help and permission to share the skills we have learned, much of which was done on their locations.

REFERENCES

1. MERCER R.F., "Liberated, Produced, Recycled or Contamination" Form. Eval. symposium, Canadian Well Logging Society 1974.

2. PETTIJOHN, F.J., Sedimentary Rocks 3rd Ed. Classification of Limestone, page 347, table 10-8.

3. WHITTAKER, A. and SELLENS, M., "Advances in Mud Logging -Conclusion: Analysis Uses Alkane Ratios From Chromatography," Oil and Gas Journ., May 18, 1987.

4. CONTINENTAL LABORATORIES Ltd, Hydrocarbon Well Logging Manual, 1988.