Michael Taylor
Exlog
Houston
Nick Eaton
Eastman Christensen
Houston
While drilling, maintaining the optimum position of the well bore with respect to productive intervals is paramount to the success of the horizontal well.
Even the best understood reservoirs are at the mercy of lateral geological heterogeneities that influence production success.
To date, horizontal drilling has targeted fractured reservoirs, thin oil plays, and reservoirs with known coning problems. Some fields are being probed using only horizontal wells.
This fifth of an eight-part series discusses the role geological services play in horizontal wells.
GEOLOGICAL SERVICES
The three key roles of geological services are to:
- Find the reservoir through the analysis of marker horizons and real-time correlation with offset data. This permits the directional driller to adjust the penetration angle into the reservoir.
- Remain within the reservoir to maximize the well bore exposure across the productive intervals.
- Evaluate the reservoir and advise the reservoir engineer of potential problems prior to completion.
Geological evaluation in horizontal wells has used both mud logging and formation evaluation measurement while drilling (FE MWD) tools during the drilling phase.
In the post-drilling phase, FE-MWD and wire line methods are used to provide logs of the resultant well bore, together with cores providing key geological insights, when available.
Therefore, the geologist, as part of a reservoir management team, has many geological evaluation tools available both while drilling and after drilling to assist in maximizing the success of the horizontal well.
The horizontal well provides the geologist, petrophysicist, and reservoir engineer with an opportunity to evaluate the reservoir in a manner not available from traditional well patterns. The lateral section of the well greatly increases the interval of the reservoir available for analysis.
Geological evaluation objectives vary with the progress of the well from kick-off point (KOP) to the end of the lateral section. Objectives also vary from the "while drilling" to the "post-drilling" phases of the well.
The well profile (ultra-short, short, medium, or long radiuses) and the lateral diameter have pronounced influences on the choice of tools to achieve these objectives.
The results of geological evaluation in the lateral section play a crucial role in dictating adjustments to the completion options for the reservoir. A correct completion is critical for a successful horizontal well.
Unanticipated faults may enhance coning unless isolated, while fracture intensive intervals need to be separated from barren zones. The sooner this information is available to the completion specialist, the more efficient the completion planning process becomes.
RESERVOIR HETEROGENEITY
An oil or gas field comprises major and minor lithological variations present at a range of scales, from mega scopic to microscopic.1 Megascopic reservoir heterogeneity can be considered as whole field variations and it results from the environment at the time of deposition, such as a meandering river.
Within this depositional environment, local variations or facies cause intrareservoir, well-to-well variation and provide macroscopic heterogeneity, e.g., a point bar or an erosion surface. Within each facies, mesoscopic heterogeneity is manifested by internal bed sedimentary structures, such as cross bedding, ripples, etc.
At the finest scale, namely microscopic heterogeneity, mineralogical or porosity variation dictates local reservoir conditions.
Fig. 1 illustrates the interrelationship of the reservoir heterogeneities as they relate to a depositionally complex reservoir. In fractured reservoirs, sets of fractures provide the heterogeneity at the macroscopic scale within otherwise weakly fractured matrix rocks.
Reservoir heterogeneity plays a significant role in segregating the reservoir into producible compartments separated by permeability barriers. The lateral section of a horizontal well may penetrate different compartments, and reservoir management will require improved understanding of the interrelationship of these compartments.
GEOLOGICAL OBJECTIVES
During the progress of drilling and evaluating a horizontal well, the objectives vary. The first objective is to find the reservoir. Next is to remain within the reservoir. The final objective is to evaluate the reservoir.
FINDING THE RESERVOIR
During the drilling phase, geological evaluation serves two primary functions: Finding the reservoir and then remaining within it. Despite advances in seismic technology, the actual vertical position of the horizontal target may be imprecise, even in a known field. Thus, finding the reservoir becomes the initial objective of geological evaluation.
When reentering an existing well, the vertical target position is well-known. However, in a new well where there is geological uncertainty, one option is to drill a high-angle pilot hole to find the top of the reservoir. If necessary, a core of the reservoir may be cut and a wire line suite run prior to side tracking the well and drilling a lateral.
One North Sea operator has used a pilot-hole core to accurately define a microfossil sequence stratigraphy within a chalk reservoir to be subsequently used to identify the vertical position of the lateral while drilling. Although it may appear an expensive option, a pilot hole may be required where marker horizons for correlation are poorly defined.
Marker horizons are formations with distinctive logging characteristics, such as a slow drilling interval, a resistive streak on an FE-MWD log, or a thin volcanic ash found in cuttings. They are critical to the directional driller's placement of the approach to the reservoir.
A marker horizon which comes in high requires a course adjustment to prevent a "crash landing" through the target. Low markers require a decreased build rate to prevent the "flyover."
Further hampering correct reservoir entry point is directional control on the well trajectory. Building the angle from KOP to horizontal requires careful planning. The closer to horizontal, the less leeway for the directional driller to make significant changes.
Depending on prevailing conditions, the well trajectory reaches a point of "no return" at some high angle and a "go/no go" decision is made to either drill ahead or plug back, reestablish KOP, and sidetrack the well.
The distance from the bit face to the directional surveying sensor and to the FE MWD sensors, and the sample lag time, may hinder making last minute course changes (Fig. 2). Therefore, for geological tools to be useful in finding the reservoir, they must supply real-time answers.
REMAINING IN RESERVOIR
Depending on the targeted application, most lateral sections have a precise vertical and horizontal target zone. Within the target, lateral lithological variation must be expected. This ranges from small faults, erosion surfaces (such as the karstic topography of the Rospo Mare field 2), chert layers in the chalk of the North Sea, and stringers of nonreservoir lithology, including shale, coal, or conglomerates. Such macroscopic heterogeneity is depicted in Fig. 2.
Additionally, the position of reservoir fluid boundaries (gas, oil, tar, and water) needs to be confirmed to maintain optimal well bore trajectory. Correctly identifying significant lithological variation from minor lateral variation and fluid boundaries to stay on target is an art requiring real-time tools.
For example, during the drilling of Atlantic Richfield Indonesia's ZUB-9 well in the Bima field, the well site geologist determined the lateral was reapproaching the top of the Batu Raja limestone. Drilling ceased, the steerable drilling system was pulled back to an appropriate location, and the well sidetracked to the low side. The well stayed within the reservoir.3
EVALUATING RESERVOIR
To maximize the knowledge derived from an extended reservoir exposure to the borehole, geological evaluation is required both during and after drilling. MWD methods log the reservoir at its least-contaminated stage, but after drilling, additional methods are required to provide a complete suite of petrophysical measurements.
Integrating all the sources of data is an essential component of successful reservoir evaluation.
GEOLOGICAL TOOLS
As in vertical wells, the tools used to evaluate the reservoir reflect the economics of the play. A routine Austin chalk or Bakken well in the U.S. may justify a well site geologist and mud logging unit, while a more complex horizontal well may use computerized mud logging, FE MWD, coring, a conveyed suite of wire line tools, and possibly a biostratigrapher. Each one of these tools has a different time frame for the availability of data for decision making (Fig. 3).
FINDING TOOLS
After the KOP, the directional driller will probably be using an MWD tool to steer the well. Depending on the characteristics of the markers, an FE-MWD gamma ray or resistivity tool may be added, with the real-time data transmission combining tool face, azimuth, and inclination with formation resistivity.
Traditional or computerized mud logging of the drilling response (drill rate and surface torque), along with the mud gas and drill cuttings, can be used independently or integrated with the FE-MWD logs as in the Far East example plotted on displacement depth shown in Fig. 4.
In the Danish North Sea, the C tuff marker is often difficult to identify in cuttings, but both drilling torque and mud gas anomalies prove to be good indicators of its presence.
One North Sea operator found biostratigraphy an indispensable tool for finding the target, e.g., identifying the top of the Maastrichtian in wells drilled in the Dan field, offshore Denmark.
In this regard, the reservoir-finding tools are very similar whether drilling horizontal or vertical wells, with one exception. As the well approaches horizontal, precise vertical depth control requires careful correlation with vertical depth logs from offset wells. When correlation is problematic, an option may be a cored pilot hole.
STAYING ON TARGET
The need for the well bore to remain optimally positioned within the target is the most significant geological evaluation difference between vertical or conventionally deviated wells and horizontal wells.
A reservoir comprises three geological evaluation components: the reservoir lithology, the pores, and the fluids. Depending on the horizontal well application (fractures, thin oil play, or coning avoidance, etc.), the tools used will vary, but all require real-time answers to stay on target.
The first tools which show reservoir lithology variation are related to drilling response (drill rate and torque). For example, slow drill rates in North Sea chalk laterals are indicative of chert layers.
However, drilling response data can be influenced by the drilling mode, whether drilling ahead with the rotary table or in a motor-driven, steering mode.
Interpreting drill rate curves for changes in rock strength and analyzing lithology change requires care to avoid blindly using vertical log interpretations in the lateral section. The rate of penetration in Fig. 4 shows considerable variation that traditional interpretation might judge to be a possible coarsening upward sequence from 937 to 910 m displacement depth.
Neither the cuttings lithology, the FE-MWD gamma ray, or porosity curves shows a major lithological variation.
In this example, the drill rate change is directly related to the use of a top-drive rig to push a 27-m stand of drill pipe into the hole. The bit moves fastest at the top of the stroke, and rate of penetration diminishes as the blocks are lowered.
This saw-tooth pattern has been observed in other wells drilled with top drives. Weight on bit (WOB) (not shown) will reflect this drilling method by starting lower at the beginning of the stand and increasing as the stand is drilled down.
Efforts to factor out drilling variable changes (WOB, rotary speed, hydraulics), using normalized drill rate calculations, such as the widely known drilling exponent (d exponent), have been unsuccessful in the lateral.
If drilling ahead using surface rotary drive is possible, surface torque variations can be logged. While steering the well with a mud motor, it may be beneficial to employ an MWD downhole torque sensor.
Changing drilling mode will cause shifts in the drill response curves, especially when reestablishing bit trajectory (see 960 m in Fig. 4).
Either MWD or mud logging is the next tool to be used, depending on the bottom hole assembly (BHA) configuration, the resultant distance to the MWD sensors, which may be upwards of 30 m (Fig. 2), the drill rate (i.e., the forward logging speed for MWD), and the MWD transmission frequency for FE-MWD sensors.
The availability of mud logging data is dependent on the sample lag time. The impacts of these time delays for the various geological evaluation tools are seen in Fig. 3.
MWD is now capable of assisting the directional driller with full directional data, the drilling engineer with near bit weight and torque, and the petrophysicist with "triple combo" equivalent data such as total and spectral gamma ray, formation resistivities, formation density, and formation porosity logs.
Some of these logging measurements may also be upward or downward sensing; for example, a focused gamma ray tool which produces upside/downside log traces.4
At this time, the availability of FE-MWD sensors may be severely limited depending on the borehole diameter of the lateral and the radius of the build section. Only MWD gamma ray logs can be measured in hole diameter less than 216 mm.
As for build rate constraints, the MWD industry faces a dilemma. It designs tools that operate in the malign drilling environment and makes them as rigid as possible. The directional driller requires flexible tools to go round the bend."
To date, MWD logging tools have been used in build rates up to the low teens degrees/30 m. Where short radius drilling is selected, FE MWD is not an option, while wire line logging is severely limited to the shortest logging sondes.
However, it may not be cost-effective to run the full suite of FE-MWD measurements while drilling. What is required while drilling are "quick-look" tools which help identify minor and major geological variation, e.g., gamma ray,5 and fluid boundaries, e.g., formation resistivity with multiple depths of investigation or differing sensor points.6
The use of memory only FE-MWD tools can only provide hindsight data and cannot actively assist steering.
Mud logging requires representative sampling of mud gas and cuttings. Frequent lag tracers, such as calcium carbide pills, are essential to ensure the sample lag is correct. To minimize formation damage, drilling the reservoir will be carried out at the lowest possible mud density although borehole stability may dictate higher mud densities. Underbalance drilling is common in some regions.
Many horizontal wells produce while drilling and the mud gas readings taken downstream of gas separation equipment may be of limited value. Also, production from the wellhead end of the lateral may mix with near-bit production and affect mud gas indicators.
Good near-balance drilling conditions yield good gas readings for analyzing the gas ratio to indicate the proximity of fluid boundaries.7
Care is necessary in interpreting mud gas curves using traditional analysis methods. The total gas curve in Fig. 4 suggests possible fluid content variation. FE-MWD resistivity (not shown) shows no variation. The gas curves reflect the drill rate, and gas normalization methods7 may be appropriate to factor out drill rate changes for the lateral section.
Knowledge of the drilling fluid used is important. The great separation between total gas (reflecting all combustible hydrocarbons) and the methane curve from the chromatograph in the ditch gas track in Fig. 4 indicates that an oil mud was used while drilling.
Adequate hole cleaning practices yield drill cuttings which can indicate changes in lithology, both for reservoir and nonreservoir rocks. Careful comparison of lithology variation with dogleg severity, stabilizer placement, and previous samples is necessary to identify cavings. Once cavings have been factored out, the nonreservoir lithology content is analyzed. Increasing percentages suggest the overlying/underlying beds are being drilled; hole inclination and local dip angles will tell which. Intermittent nonreservoir lithology percentages indicate stringers.
In Fig. 4, silty shale percentage in the cuttings lithology column between 931 and 961 m disappeared after the bit was pulled to change BHA. Subsequent drilling with the new BHA does not show this persistent silty shale. The FE-MWD logs show no indication of shales.
Post drilling analyses suggest either a hole cleaning problem, a stabilizer side-cutting on a shale stringer in the lateral, or pipe whipping in the build section of the well. No single solution is possible for this data set.
The reservoir lithology is then analyzed for mineralogical and visual porosity variations to try to identify microscopic heterogeneity in the reservoir. Hydrocarbon fluorescence under ultraviolet light is also evaluated for mesoscopic and microscopic heterogeneity in reservoir fluids.
Fluorescence is known to vary in reservoir fluid layers,7 but there is no known documented proof of well bore steering using this method. When drilling limestone/dolomite plays, calcite/dolomite variations of cuttings measured by calcimetry may assist in identifying the horizon of the well bore.
Well site micropaleontologists may be used on North Sea chalk wells to identify correct well bore trajectory from microfossil stratigraphy, although reworked fossils within the chalk hinder the evaluation.
It goes without saying that any lost circulation problems and their cures severely impact the effectiveness of mud logging, but can assist in fractured reservoir evaluation by indicating where the fractures are located.
RESERVOIR EVALUATION
While mud logging fractured plays, drilling response changes can indicate the positions of fractures or fractured intervals. Start-stop drilling rates and torque, if monitored at small measured depth intervals, can be used. Other good indicators are changes in delta flow (mud flow out of the well minus flow in) and the resultant gain or loss in mud.
Gas peaks over background levels for both hydrocarbons and carbon dioxide (in carbonate reservoirs) also indicate fractures, especially when free calcite is identified in drill cuttings.8
Cores may be available for reservoir analysis. The well profile dictates the length of coring assembly, core barrel length, and resultant core length.
In a short-radius hole, a 1 m long core barrel can recover a 0.45 m long, 63 mm diameter core. In medium-radius holes, coring is possible with 10 or 20 m long core barrels for core diameters ranging from 60 to 133 mm.
Cores have been routinely cut as soon as the lateral is commenced. Shales, including some cored on air, unconsolidated oil sands, fractured Austin chalk, North Sea chalks, carbonates, and sandstones have been cored to date with acceptable recovery rates (Table 1). Cores from the far end of the lateral are less common, but have been successfully cut and recovered.
Planning is fundamental to horizontal coring operations. Foremost in the planning stages are directions given by the geologist and reservoir engineer as to exactly what information they want to derive from the core. These data will guide the coring service company in properly selecting a coring system best designed to recover cores meeting geological and reservoir engineering objectives.
Furthermore, experience of the well site coring personnel will have a major impact upon the success or failure of a particular coring operation. This is particularly true while coring the lateral, since the build/drop of just a few degrees of hole angle can mean the success or failure of staying within a particular target zone.9
FE-MWD tools can be run both while drilling and after drilling. Measurement after drilling offers advantages since the tool logging speed, tool rotation speed, and tool hydraulics can be controlled for optimum data retrieval and downhole memory usage. Controlled rotation speed is crucial for sensors like focused gamma ray4 and also for FE-MWD nuclear tool correction factors for hole size effects.10
The steering BHA should be reconfigured to place FE MWD sensors nearer to the bit to enable measuring closer to total depth. The logging environment is at its most benign with vibration levels and downhole torque levels minimized, improving overall tool performance.
Furthermore, the "lost-in hole" risk is more controllable, and tools are downhole for a much shorter time. This serves to limit the cost to the operator. The FE-MWD logs in Fig. 4 were run after drilling.
If the lateral is not logged while drilling, hole problems can preclude either MWD or wire line logs. Additional rig time is required to ream and circulate the tools through the lateral. The use of repeated logging to indicate invasion rates and movable hydrocarbons requires both while-drilling and post-drilling FE-MWD tool runs.5
Additionally, the MWD economics for the current available measurements become less favorable with respect to wire line tool options when full suite FE-MWD tools are used to drill the lateral.
Traditional wire line measurements require special tool conveyance for hole angles in excess of 60 from vertical. Conveyance for horizontal wells includes drill pipe or coiled tubing. These methods and their advantages and disadvantages have been covered extensively by both operators and service companies and are not examined in this discussion.11-14
DRILLING THIN SANDSTONE
The following case study reveals how formation evaluation is used in drilling a horizontal well.
In an old oil field in the U.S., a horizontal well was targeted at a thin 8 ft (2.45 m) 30 API oil-bearing sandstone (porosity 30%, permeability 90 md) at 2,116 ft (645 M).
A medium-radius horizontal well was designed, building at 14/100 ft (14/30 m) from a kick-off point at 1,710 ft. The targeted horizontal displacement was planned to be 2,500 ft.
The plan was to enter the reservoir at a measured depth of 2,351 ft and remain in the reservoir to a total measured depth of 4,443 ft. Thus, 2,092 ft of well bore or 47% of the well length was to be drilled in the reservoir.
Markers while drilling included a limestone at 1,700 ft true vertical depth (TVD) to indicate kick-off point, and a limestone at 1,960 ft and a siltstone at 2,085 ft to indicate proximity to the reservoir. The prognoses of the reservoir is detailed in Fig. 5.
While drilling the original lateral, the project geologist was convinced that the directional driller had drilled through the pay and that an upward course correction was required.
Because of the difficulty in controlling the bit when a thin reservoir is not overlaid/underlaid by high compressive strength rocks, coupled with geological uncertainty, the well course was turned upwards and out of the reservoir (Fig. 5).
A second course correction was required to return to the reservoir. Eventually, the BHA was stuck short of target and the well sidetracked.
During drilling of the first sidetrack, the kick-off point was too deep, and the BHA did not build angle fast enough. The reservoir was drilled through. The second sidetrack was more successful. A summary mud log is presented as Fig. 6.
The mud log is plotted with the long axis being the horizontal displacement to the north scaled in feet (4,000 1,400 ft) from kick-off point. The upper track depicts the well bore profile with reference to the prognosed stratigraphy of siltstone, sandstone, and shale.
The reservoir was known to be glauconitic at the top, have the best shows in the middle, and become increasingly shaley at the base. The vertical exaggeration is 30 times with the vertical axis showing the interval 2,108 2,128 ft TVD.
The other three tracks are traditionally derived mud logging data which have been averaged over each survey length (9 m).
The hydrocarbon show rating uses total gas level, chromatograph compositional analysis, and drill-cutting show evaluation including visual fluorescence and solvent extraction.
The cuttings lithology depicts the relative abundance of sandstone and siltstone cuttings. The lowest track shows average drill rate between surveys in feet per hour. Maximum drill rates exceeded 60 m/hr for short intervals.
Note the bit change at 1,320 ft and the impact it has on drill rate before and after the change. No MWD or wire line logs were run on this well.
REFERENCES
- Finley, F.J., Laubach, S.E., Tyler, N., and Holtz, M.H., "Opportunities for Horizontal Drilling in Texas," Geological Circular 90-2, University of Texas at Austin.
- Dussert, P., Santoro, G., and Soudet, H., "HORIZONTAL WELL OPERATIONS-1: A decade of drilling developments pays off in offshore Italian oil field," OGJ, Feb. 29, 1988, pp. 33-9.
- Barrett, S.L., and Lyon, R., "Navigation Drilling Effective in Horizontal Wells in the Java Sea," Drilling, May/June, 1988.
- Jan, Y., and Harrell, J.L., "MWD Directional-Focused Gamma Ray-A New Tool for Formation Evaluation and Drilling Control in Horizontal Wells," Paper A, SPWLA 28th Annual Logging Symposium, 1987.
- Cunningham, A.B., Jay, K.L., and Opstad, E., "Applications of MWD Technology in Non-Conventional Wells, Prudhoe Bay, North Slope, Alaska," Paper D, SPWLA 31st Annual Logging Symposium, June 24-27, 1990.
- Gianzero, S., Chermali, R., and Su, S.M., "Induction, Resistivity and MWD Tools in Horizontal Wells," Paper N, SPWLA 30th Annual Logging Symposium, June 11-14, 1989.
- Whittaker, A., and Sellens, M., "Advances in Mud Logging 3 parts," OGJ, Mar. 30, Apr. 20, May 18, 1987.
- Haas, R.C., and Stokley, C.O., "Drilling and Completing a Horizontal Well in Fractured Carbonate," World Oil, October 1989, pp. 39-45.
- Eaton, N., "Coring the Horizontal Well", ASME Drilling Technology Symposium, Vol. 27, New Orleans, January 1990, pp. 65-9
- Best, D., Wraight, P., and Holenka, J., "An Innovative Approach to Correct Density Measurements While Drilling for Hole Size Effects," Paper G, SPWLA 31st Annual Logging Symposium, June 24-27, 1990.
- Spreux, A., Georges, C., and Lessi, J., "HORIZONTAL WELL OPERATIONS-6: Most problems in horizontal completions are resolved," OGJ, June 13, 1988, pp. 48-52.
- de Montigny, O., Sorriaux, P., Louis, A.J.P. and Lessi, J., "HORIZONTAL WELL OPERATIONS-Conclusion: Horizontal well drilling data enhance reservoir appraisal," OGJ, July 4, 1988, pp. 40-8.
- Stang, C.W., "Alternative electronic logging technique locates fractures in Austin chalk horizontal well," OGJ, Nov. 6, 1989, pp. 42-5.
- Fertl, W.H., and Nice, S.B., "Well Logging in Extended Reach and Horizontal Boreholes," OTC 5828, 10th Annual Offshore Technology Conference, May 2-5, 1988.
Copyright 1990 Oil & Gas Journal. All Rights Reserved.