Shahri, Mojtaba (Apache Corp.) | James, Moisan (Apache Corp.) | Vasicek, Alan (Apache Corp.) | De Napoli, Roy (Apache Corp.) | White, Matthew (Apache Corp.) | Behounek, Michael (Apache Corp.) | D'Angelo, John (University of Texas at Austin) | Ashok, Pradeep (University of Texas at Austin) | van Oort, Eric (University of Texas at Austin)
Given the intensity of drilling operations in the North American unconventional reservoirs and the quality and amount of data gathered during a drilling operation, leveraging those data along with advanced modeling techniques for optimization purposes is becoming more feasible. In this study, historical data and advanced physical modeling are utilized to better understand and optimize the bottom-hole assembly (BHA) performance in drilling operations. A comprehensive data set is gathered for more than 300 BHA runs in the span of three years. This extensive data set enables thorough examination of the variation in the operational parameters and its effect on the drilling performance.
Different indices are used to determine and evaluate drilling performance, such as rate of penetration (ROP). Excessive tortuosity in a well can have many detrimental effects while drilling such as excessive and erratic torque and drag, poor hole cleaning (cuttings removal), low ROP, along with problematic casing and/or liner runs and associated cementing procedures. In this paper, a tortuosity index (TI) is used to quantify the drilled well quality and correlate it to ultimate drilling performance. In the next step, patterns are extracted and used along with physical modeling for optimizing drilling performance before the well is drilled.
The corresponding tortuosity index can be used as a proxy for the well path smoothness and may be used for quantifying parameters affecting drilling performance. According to historical drilling performance data, there appears to be a strong relationship between wellbore tortuosity and ROP. If drilling operating parameters (e.g., BHA configuration, directional company's performance, target formations, bit specification, mud types, etc.) can be related to the TI based on historical data, such parameters can be modified for optimizing the performance before the well is drilled.
By investigating the historical data, different trends have been extracted. In addition, different models can be built to predict drilling performance (e.g., TI) prior to drilling and according to new well design specifications. Based on data from more than 300 BHA runs and using advanced physical modeling, the most strongly correlated parameters to drilling performance have been determined and shown using different case studies. Such a historical database along with modeling techniques are used to predict well quality and drilling performance during the design phase. Using this method, well design specifications can then be optimized to enhance drilling performance and reduce the cost.
Hole deviation is the unintentional departure of the drill bit from a preselected borehole trajectory. Whether it involves drilling a straight or curved-hole section, the tendency of the bit to walk away from the desired path can lead to drilling problems such as higher drilling costs and also lease-boundary legal problems Figure 1 provides examples of hole deviations. It is not exactly known what causes a drill bit to deviate from its intended path. It is known that some resultant force acting on a drill bit causes hole deviation to occur. The mechanics of this resultant force is complex and is governed mainly by the mechanics of the BHA, rock/bit interaction, bit operating conditions, and, to some lesser extent, by the drilling-fluid hydraulics.
The most common deviation tools for directional drilling are steerable motor assemblies (or so-called positive-displacement motors [PDMs]) and rotary steerable systems (RSSs). Adjustable-gauge stabilizers, known as "2D rotary systems," have become quite popular to run with the rotary and PDM assemblies to control inclination. Whipstocks, especially casing whipstocks, are used routinely to sidetrack out of cased wellbores. Other tools, such as turbines, are used mainly in Russia, and jetting bits are seldom used today. The most important advancements in trajectory control are the steerable motor assemblies, which contain PDMs with bent subs or bent housing.
Hydrocarbon production can be hindered as a result of fluid-induced formation damage caused by shale damage (swelling, sloughing, or fines migrating) or chemical damage (insoluble residue or polymer buildup). The proper selection of completion and stimulation fluid with additives provides the leading approach to mitigate formation damage.
Formation-specific damage mechanisms were determined from formation core, drilled cuttings, and outcrop materials for more than 100 North American resource shale samples. The formation materials were characterized using x-ray diffraction (XRD), cation exchange capacity (CEC), swelling sensitivity time (SST), mechanical stability turbidity (MST), and column flow testing to determine mineralogy, fluid sensitivity, and dominate fluid-induced damage mechanism. Preventing formation damage is predominately achieved with cationic clay stabilization chemicals. The efficacy of numerous chemical additives prepared at the same activity but with varied molecular weights (MWs) from 0.1 to 1,200 kDa was evaluated on ultra-low permeability shale samples based on reducing the swelling, fines generation, and mechanical destabilization tendencies. The same treatment chemicals were evaluated for permanency, compatibility with anionic friction reducer (FR) polymers, and mobility within porous media to determine the ideal North American formation stabilization material.
Fines generation was determined to be the dominant fluid-induced damage mechanism for ultra-low permeability North American hydrocarbon-producing formations. Clay content for these active formations range from 1 to 70 wt%, with an average of 30 wt% and a CEC of 4.5 milli-equivalence (meq)/100 g, indicating that most North American formations have moderate fluid instability. Fluid sensitives found an average swelling damage comparable to a 1 wt% smectite sample (30 seconds) mass loss due to mild mechanical agitation similar to an illite sample (3.2 wt%/hr) and fines generation due to flow approximately half of an illite sample (6.22 mg/PV). Prevention of these fluid-induced formation damage effects was determined for cationic clay stabilization chemicals ranging in MWs from monovalent salt solutions to large polymeric materials. Highly mobile monovalent salts effectively prevent swelling and remain compatible in an anionic FR solution; however, these treatments are temporary and less effective for remediating fines generation. Increasing the MW of cationic treatments improves the performance in terms of preventing swelling, fines, and wash-off; however, if the MW increase is too large, the polymers reduce permeability and become incompatible with anionic FR polymers. There is a range of moderate MW materials that provides permanent protection against swelling and fines damage while remaining compatible with anionic FRs. This range of moderate MW cationic treatments is the optimal chemical additive for most North American formations, offering the most effective protection against prevalent fluid-induced formation damage mechanisms while preventing chemical damage.
The bottom hole assembly (BHA) is a portion of the drillstring that affects the trajectory of the bit and, consequently, of the wellbore. The BHA design objective for directional control is to provide the directional tendency that will match the planned trajectory of the well. The bit side force is the most important factor affecting the drilling tendency. The direction and magnitude of the bit side force determine the build, drop, and turn tendencies. Note: Rotary Steerable Assemblies are a notable exception to the comments below and are used as directional assemblies that can be steered and are used to build, drop, or hold angle and can be controlled from surface.
The success of a pilot milling operation is dependent on the mill design, adherence to correct milling parameters and precise location of stabilizing members in the bottomhole assembly (BHA), especially while milling through large casings such as 20 inch inside 30 inch conductor. This paper discusses the importance of correct mill design and stabilization of the BHA, along with field results from milling with under-gauged mill and stabilizers.
Pilot milling interventions to facilitate open-hole side-tracking can be very effective and cost-efficient, especially in cases where retaining the original borehole size is necessary for further workover operations, for example, when liner is milled for this purpose. Pilot milling is a suitable option where sidetracking with a whipstock is not viable, as when casing has collapsed, with internal diameter restrictions, or situations where irreparable surface damage to conductor pipe and casing have occurred due to corrosion. Such situations might result in losing an offshore platform slot, which is a huge cost to operators.
One such situation was encountered where 30 inch conductor pipe parted at the water line due to corrosion. Prolonged exposure to corrosion further led to 20 inch casing parting at the water line as well. Surface repairs were attempted but were unable to arrest annulus leakage. In order to recover the slot, an improved and specially designed pilot mill was used. A stabilized milling bottom-hole assembly with precise sizes and locations of stabilizers was incorporated. This new mill design resulted in milling 585.6 feet of 20 inch casing with an average rate of penetration (ROP) of 2.6 ft/hr. The new mill design resulted in good mill life and only two mill runs were made in the entire milling operation. Results of torque and drag simulations to study the bending stresses and torsional stresses on mill string components while milling are discussed. Catastrophic effects of using under-gauged mill and stabilizers were also examined.
This improved mill and stabilized bottom-hole assembly design offers optimum ROP, improved mill life, reduced surface vibrations and a fine metal cutting structure that eases metal debris handling at surface.
Sengupta, Partha (Oil and Natural Gas Corporation Limited) | Katre, Narendra (Oil and Natural Gas Corporation Limited) | Suman, Abhinav (Oil and Natural Gas Corporation Limited) | Das, Barnali (Oil and Natural Gas Corporation Limited) | Pawar, Anil (Oil and Natural Gas Corporation Limited) | Deshpande, Sunil (Oil and Natural Gas Corporation Limited)
In any onshore gas installation, bath-heaters and high pressure separators are provided as standard surface facilities to take production from high pressure wells having hydrate forming tendency. Medium pressure separators are also provided to take production from medium pressure gas wells. The paper deliberates on an optimized surface installation for handling high pressure well fluids with possibilities of hydrate formation. The study has been carried out through steady state multiphase simulation considering pressure & production profile of the wells, consumer requirement and flow assurance i.e. hydrate formation. An optimized process scheme and production strategy is presented for early production from both high pressure and medium pressure gas wells in a single separator and without any bath heater.
Based on well test data, well completion data and pressure profile, simulation studies are carried out in steady-state multiphase flow simulation software to look into possibility of hydrate formation in the flow lines or in process piping. Flow from wells having high well-head pressures in the range of 120 to 165 kg/cm2g (ksc) are simulated by varying the separator pressure, flow line size & length and choke arrangement. Flow simulations are carried out for different choke combinations and flow line arrangements to keep well fluid temperature above hydrate formation temperature in the entire flow path from well head to separators.
It was established from simulations that flow from the well having highest production as well as highest well head pressure of 165 ksc can be taken by operating the separator at 33 ksc and adopting a multi-choke arrangement along the flow line without any possibility of hydrate formation in the system. The multi-choke arrangement consists of putting chokes including well head choke at well site, at installation inlet and the final choke at installation inlet manifold. The arrangement also envisages additional small length of flow line as buried portion near installation inlet to take advantage of heat gain from soil. From 2nd year onwards of the profile period, it is observed that with reduction in well head pressure to 132 ksc as per profile, the well can be produced by operating the separator at lower pressure without any hydrate formation. For rest of the wells, only multi-choke arrangement is found to be sufficient to prevent hydrate problem while operating the separator at even lower pressure throughout the profile period. It is also observed that higher production can be taken from the wells from 2nd year onwards on account of operating the separator at lower pressure.
The optimized scheme has marked deviation from the earlier proposed standard scheme with substantial reduction in number of equipment and consequent reduction in CAPEX & OPEX. This novel process scheme and production strategy eliminate the need for investment in both high pressure separator and hydrate mitigation measures like heat tracing, methanol injection or bath-heaters. This innovative production strategy also facilitates better recovery from the gas wells on account of operating the separator at lower pressure.
Historically underreaming while drilling (UWD) operations were implemented in offshore field in Azerbaijan to decrease Equivalent Circulating Density (ECD) and have better hole quality for casing running. Lithology in this UWD, 8.5 × 10.25-inch section consists of sand and shales with 3-5kpsi Unconfined Compressive Strength (UCS). Well trajectory has planned dogleg severity up to 3-3.5 deg/30m. In such a condition underreaming operations are known to be more challenging and complex compared to conventional drilling with bit only. In the offset well, an operator had fatigue related twist off at the reamer's lower sub connection which contributed to 58 hours of NPT.
Our challenge was to come up with the root cause of the twist off and then suggest changes in BHA to avoid this and prove that the modified BHA performs as expected. Our finite element analysis (FEA) based 4D modeling software can identify different vibrations (axial, lateral, stick slip), bending stresses and bending moment of each component in the BHA. Using this software, we were able to come up with the root cause of the twist off, which was due to high bending stress.
In UWD there are two cutting structures in the BHA, so optimizing both cutting structures has a significant impact on the overall performance. Successful run key points are to analyze the underreamer placement in BHA, operating parameters selection for different scenarios (when both bit and undereamer are in the same rocks or when the bit is in soft and undereamer is in hard rock), lateral vibrations and whirling phenomenon which can potentially damage and develop fatigue on BHA components. Multiple BHA's were simulated and based on the results the most stable BHA was recommended for the upcoming well.
The operator implemented the recommended BHA and a total of 1200m was successfully drilled and opened in one run without any NPT. All directional requirements were achieved and both bit and underreamer came out in good condition which confirmed that the new optimized BHA was stable in the downhole drilling conditions. The liner was also run without any issue confirming the borehole quality.
This paper will review the results of analysis and how modeling prediction was validated in the field.
A new class of permanent clay stabilizers has been developed inorganic based on an aluminum/zirconium-based compound. The increased charge density of the molecule allows it to bind more strongly to swelling clays, while its relatively low molecular weight allows it to stabilize the clay permanently without causing formation damage by blocking the pore throats and reducing permeability.
The most commonly used clay stabilizers are organic and inorganic chloride salts including trimethylammonium chloride, potassium chloride, and choline chloride. These salts have been used for years, are effective in most wells, and are both cheap and abundant. However, their high water solubility and the relatively small size of the cation means that these products are highly mobile and thus are quickly washed away during flowback. Several chemical derivatives were made from a tri-functional amine by reacting it with organic and inorganic acids such HCl, acetic acid, and formic acid; as well as alkylating agents, including chloromethane, benzyl chloride, diethyl sulfate, and paraformaldehyde.
Certain cationic polymers have also proven useful as clay stabilizers. These much larger molecules are not as easily washed away due to steric hindrance and a much higher charge density per molecule. These products have proved useful as long-term clay stabilizers, but their high molecular weights can lead to formation damage by causing them to be filtered out on the rock face.
In this research, several laboratory tests were carried out on the new clay stabilizer. These tests included coreflood experiments conducted on Berea sandstone cores to assess the stabilizer at high temperatures and the influence of different acids on its performance. Coreflood effluent samples were analyzed using inductively coupled plasma optical emission spectrometry (ICP-OES) to measure the concentrations of aluminum and zirconium.
This new permanent clay stabilizer improved productivity from formations that have high clay content by minimizing clay swelling and thus preventing formation damage caused by clogged pore throats and subsequent loss of permeability. It worked well at temperatures up to 250°F and with 15 wt% HCl and regular mud acid (12 wt% HCl, 3 wt% HF).
In Vietnam, there was a need of a lean surface casing due to restricted drift inside diameter (ID). The 2nd slot of the splitter conductor only have 13-1/2" ID max pass through. The practical option is to drill with 12-1/4" bit and open to 14-1/2" hole to set 11-3/4" casing OD. Similar reasoning for the intermediate hole that will require to under ream the hole from 10-5/8" bit to 12-1/4" hole and set 9-5/8" casing OD. Although these under reaming operations are commonly practiced, the technical limitations are still inefficient and compromising. Conventional reamers still have limited activation/deactivation cycle for operational flexibility and long rathole of the reamer to bit depth for casing shoe placement.
The long awaited technology is now available with the presence of intelligent reamers that have unlimited activation & deactivation cycles and can be placed directly above the rotary steerable system for shortest possible rathole. The setup is to combine two intelligent reamers in a single BHA. The 1st reamer placed strategically on top of the MWD & LWD tools while the 2nd reamer is directly above the rotary steerable system tool. As both reamers can be both activated and deactivated through downlinking, the reamer has to be activated simultaneously to control the risks associated with hole opening and LWD data acquisition. The 1st intelligent reamer will be activated first while drilling the section formation and the 2nd intelligent reamer will then be activated at section TD to ream and shorten the rathole. For the purpose of cleaning the hole effectively, both reamers can be deactivated to execute high flow and RPM without creating new cuttings from the reamer blades and avoid making a bigger hole at the low side.
This enabled shoe to shoe drilling while under reaming and achieving less than 10m rathole. These operational capabilities saved at least 50% of the section rig time compared to having a 2 trip system. Combination of reduced casing shoe rathole and open hole exposure mitigated the well bore instability risks and helps in managing mud weight for both hole section intervals. The unlimited activation cycle provided flexibility in operations particularly in dealing with hole cleaning and wiper trips. Plus, the intelligent reamer provides realtime reamer diameter which gives confidence on the drilled hole size for casing running preparation and decisions.
Intelligent reamers have unique tool features that differentiate from the rest of current industry technologies. This feature helps to eliminate the risk of under-reamer balling, which improve the rate of penetration. The success of the operation has spread throughout operators in Vietnam, and now the intelligent reamer is considered as a game changer application in drilling lean casing profiles.