Ashraf, Qasim (Weatherford International Ltd.) | Khalid, Ali (Weatherford International Ltd.) | Luqman, Khurram (Weatherford International Ltd.) | Hadj-Moussa, Ayoub (Weatherford International Ltd.) | Shafique, Muhammad Bilal (MOL Pakistan Oil & Gas Co. B.V.) | Abbas, Khurram (MOL Pakistan Oil & Gas Co. B.V.) | Tashfeen, Muhammad (MOL Pakistan Oil & Gas Co. B.V.) | Khan, Shahjahan (MOL Pakistan Oil & Gas Co. B.V.) | Jameel, Rizwan (MOL Pakistan Oil & Gas Co. B.V.)
The Northern Potwar Plateau of Pakistan is known for its severe geological features. Many wells have been drilled in the region, but geological correlations in neighboring fields have proven to be challenging. Excessive tectonic activity and faults have resulted in formation repetitions, abnormal in-situ stresses, and variable formation pore and fracture pressures.
One such field in the region is MDK field, where the operator was in the process of drilling a second well. Drilling of the 8 ½-in. hole section was in progress at 11,004 ft. (3,354 m) when the Bahadur Khel Salt formation was encountered. Upon drilling further into the formation, the operator encountered severe hole stability issues coupled with lost circulation. While in the salt formation, whenever circulation was stopped and annular pressure losses were eliminated, the drill string would become stuck. Upon resuming circulation, the pumping pressure would rise abruptly. The formation was highly stressed and was exhibiting a creeping behavior. Any reduction in the bottom hole pressure (BHP) would cause the formation to creep into the wellbore.
The operator spent a month attempting to drill through the highly stressed plastic salt formation, without success. The oil-based mud system was already weighted up to its maximum, and no other conventional means existed of controlling the creeping salt. The operating company had already spent ~USD 19 million dollars on the well, and was considering abandoning it after a nearby well in the same formation had been abandoned despite four unsuccessful sidetracks.
Maintaining a constant bottom hole pressure (CBHP) across the formation at all times was the only way to stabilize the salt formation and lost circulation treatment. Only managed pressure drilling (MPD) could achieve the application of CBHP. An MPD system would enable the operator to compensate for the lack of BHP by applying surface backpressure, thereby maintaining the target pressure across the formation at all times. With the help of the MPD system, the operator also sought to calculate the formation creep rate, so as to evaluate a time window for running in and out of the hole.
Besides drilling, the operator also intended to isolate the challenging section with a liner. With proper planning, the MPD system could help to achieve this objective.
A full MPD system was deployed to the wellsite and drilling resumed with a CBHP in dynamic and static periods. By CBHP MPD, the operator was able to tag bottom. Drilling and underreaming of the 8 ½-in. hole section resumed and continued until reaching the target depth of 14,745 ft. (4,494 m). After drilling, the 7-in. liner was set and cemented to the target depth using MPD.
Applying CBHP MPD enabled the operator to drill through 3,832 ft. (1,168 m) of the hole section and save the well from abandonment. This paper studies the design, execution, and lessons learned when applying MPD on the subject well.
The PDF file of this paper is in Russian.
This paper describes the implementation of pressurized mud cap drilling (PMCD) technology, a variant of Managed Pressure Drilling (MPD), a successful technique frequently used on oil and gas fields in Kazakhstan. It also considers the planning phase, operational aspects, and results of drilling with the PMCD technique through challenging formations.
PMCD technology with a rotating control device (RCD) is a form of blind drilling, where the drilling fluid and formation cuttings are not transported to the surface. It is a non-conventional drilling technique designed to maintain annular wellbore pressure to prevent total loss of circulation. A sacrificial fluid (SAC) is injected through the drill string and light annular fluid is pumped down from the annulus to maintain borehole fill and prevent annular gas migration.
Wells in this field have encountered uncontrollable losses while drilling sections of the fractured carbonate. As a result, the application of PMCD technology to meet those challenges was an obvious choice in order to achieve target depth. Conventionally drilling of the 8-in. section resulted in fluid losses of more than 450 m3. Consequently, passing through these challenging zones the rig crew switched from conventional drilling to PMCD. The wells were then successfully drilled using the PMCD method, without any issues or well-control incidents, and planned TD was attained. By enabling the client to reach TD, Weatherford PMCD equipment transformed a previously undrillable well into a potentially valuable asset. This operation demonstrated that PMCD can be a viable drilling technique for future wells in the field.
PMCD technologies included reduced consumption of lost-circulation material (LCM) and reduced loss of mud to the formation, keeping the wells economically viable. The main objectives of these wells were to drill safely and efficiently to target depth (TD), to deliver the wells for production on schedule, reduce non-productive time (NPT), minimize the drilling risks and hazards, and optimize the drilling program.
The field of interest involves penetrating a predominantly dolomite and dolomitic limestone formation associated with highly pressurized saltwater equivalent to as high as 157 pcf (21 ppg). The most over-pressurized zones are encountered across the ±1,000 ft. base layer of this formation where the majority of flow incidents occurs. This is further exacerbated by the extremely narrow mud window of 0.5-1.0 pcf (0.07-0.14 ppg) between the pore pressure and fracture pressure. Such conditions may lead to risky operations that include well control, high mud weight (MW) design complications, differential sticking, drillstring design limitations, liner equipment failure, poor cement job, etc.
Fully automated managed pressure drilling (MPD) systems are utilized to drill the 12 in. hole section and walk the tight window across this rock. This approach allows for applying surface back-pressure (SBP) and accurately holding constant bottomhole pressure (BHP) while keeping constant MW throughout the drilling operation. This operation also witnessed the application and utilization of fully automated MPD systems as means to run and cement a 9-5/8 in. liner across this troublesome zone.
Conventionally running liners in excessively high kill MW of ±155 pcf (20.72 ppg) while dealing with tight margins is particularly challenging as it yields total losses due to the surge effect. Conventional cement jobs also mandate filling the hole with high kill MW before the cementing operation, inducing losses and resulting in poor well integrity, leaking liner packer, wet casing shoe, etc. Utilizing MPD systems to run and cement the 9-5/8 in. liner allowed for multistage hole displacement, filling the hole with a lighter MW, and maintaining constant BHP throughout the entire operation regardless of any surface tool failure (pump cavitation, leaking cement head, and surface lines, etc.).
This paper details the planning and design phase along with the operational sequence of running and cementing the 9-5/8 in. liner with fully automated MPD systems. A case study will be highlighted to establish lessons learned and best practices.
Al Moraikhi, Rasha (Kuwait Oil Company) | Kulkarni, Nitin (Kuwait Oil Company) | Patil, Dipak P. (Kuwait Oil Company) | Sounderrajan, Mahesh (Kuwait Oil Company) | Verma, Naveen K. (Kuwait Oil Company) | Quttainah, Riyad (Kuwait Oil Company) | Al-Kandari, Eman (Kuwait Oil Company) | Al-Mohailan, Mohannad (Kuwait Oil Company)
Jurassic Reservoirs in Abduliyah field of West Kuwait are characterized by abnormal pressure variation within and across Jurassic formations, which cause profound drilling problems such as well kicks and mud losses resulting in increased drilling time, cost and materials in addition to reservoir damages.
The development of Najmah –Sargelu (NJ/SR) unconventional fractured reservoir requires drilling through high-density fracture swarms to ensure well productivity, which in many instances result in "alternate loss & gain scenario," occasionally, making the well control options limited. On the other hand, drilling through Marrat section encounters drilling difficulties such as mud loss and differential sticking in depleted middle Marrat layers juxtaposed to high-pressure layers of upper intervals. Keeping the above problems in mind, Managed pressure Drilling (MPD) was applied first time in both 9-1/4″ NJ-SR & 6-1/2″ Marrat reservoir sections in a deviated well of Abduliyah field. The Use of MPD in this well offered several advantages and improvements in drilling and completion performance as given below:
The paper aims to share the successful case study of drilling through Jurassic reservoir sections of Abduliyah deviated well using MPD technology along with lessons learned and benefits for its future implementation in similar wells across all KOC assets
Nana, D. (Schlumberger) | Buyers, G. (REPSOL) | Burton, D. (REPSOL) | Gomes, J. (REPSOL) | Pulpan, E. (REPSOL) | Tickoo, A. (REPSOL) | Meyer, A. W. (Schlumberger) | Munozrivera, M. (Schlumberger) | Silko, N. (Schlumberger) | Demidov, D. (Schlumberger)
Potential reservoir formation damage was avoided when curing up to 87.4 m3/hr (550 barrels per hour (bbl/hr)) losses of drilling fluid in a carbonate reservoir. In addition to traditional lost circulation assessment and treatment consideration, self-degrading fibers were used as part of the lost circulation system, and these preserved the reservoir from any consequential formation damage.
The treatment procedure consisted of pumping a given volume of treatment pill through bypass ports present in the drilling string and displacing it down to the loss zone (located 56 m below the bit). Managed pressure drilling (MPD) was used to minimize hydrostatic pressure above the said loss zone during pill placement (statically under-balanced mud weight). Since drilling was meant to continue after the treatment, the pill had to be squeezed to and through the reservoir to prevent loss from re-occurring when drilling resumed. The only available solutions at the time of need were either a thixotropic acid soluble cement plug (TASCP) or, the proprietary degradable fiber. Preference was given to the degradable fiber since it involved less rig time and does not need any subsequent dissolving treatment. An appropriate spacer was pumped ahead and behind the degradable fiber to prevent intermixing of incompatible fluids. The treatment was pumped using the rig mud pumps.
The loss rate registered prior to the treatment was 87.4 m3/hr (550 bbl/hr) at a pumping rate of 2650 l/min (700 gal/min). The equivalent circulating density (ECD) was 1.22 SG (10.2 ppg). Out of 19 m3 (120 bbl) of prepared degradable fiber pill, 15.6 m3 (98 bbl) were pumped and displaced into the reservoir, leaving the estimated top of the pill at 5850 m measured depth (MD). The top of the loss zone was estimated to be at 5856 m TVD/MD. The bypass port was then closed. It was then observed that the loss rate reduced to 3.65 m3/hr (23 bbl/hr) when circulating the hole clean at 5800 m TVD/MD and maintaining the same ECD of 1.22 SG (10.2 ppg) with the help of MPD equipment; pumping down string at 3028 l/min (800 gal/min) and boosting the marine riser at 757 l/min (200 gal/min). This pill was designed to self-degrade after 4 days. The pill lasted for 5 days, and the loss rate came back to its original level, providing evidence that the fiber had self-degraded as expected. MPD helped minimize further loss through the reduction of hydrostatic overbalanced pressure. Later, openhole wireline logs were run and did not reveal any change in expected porosity or permeability.
This paper presents a case study in which the introduction of degradable fiber through a bypass port in the bottomhole assembly (BHA) cured severe loss of nonaqueous fluid (NAF) in a deepwater exploration well without damaging the formation. This case provides evidence that properly designed fiber-based pills can be used in the reservoir section without any major consequences on the well production potential.
With more wells drilled into hydrocarbon bearing formations, operators are forced to drill into challenging plays with narrow pressure margins. Successful drilling in depleted zones with isolated, high-pressured fractures is difficult and requires managed pressure drilling (MPD). Once the well is drilled, the operator should achieve zonal isolation by pumping cement across the zones of concern without inducing lost circulation or gains. Managed pressure cementing (MPC) pumps cement in a hydrostatically underbalanced environment with pressure applied at surface using an automated choke system (ACS) to maintain a target equivalent circulating density (ECD) between the highest pore pressure (PP) and the lowest fracture gradient (FG) of the well. Communication between cementing operations and MPD software allows automatic system adjustment without manual input. The MPD hydraulic model tracks multiple fluids with different densities, rates, and rheological properties throughout the wellbore. A rig pump diverter (RPD) allows for constant bottomhole pressure (BHP) by manipulating the surface choke pressure if unplanned shutdowns occur. Successful MPC operations have been conducted using the ACS in the Paradox Basin with narrow pressure windows and in the Piceance Basin with high reservoir pressure zones. The nature of cement operations can be unpredictable, but through the automatic managed pressure cementing (AMPC) process, a target ECD can be identified and constant BHP maintained to design and deliver dependable barriers tailored to minimize risk and maximize production.
Riphean anisotropic cavernous-fissured carbonate reservoirs of oilfield at East Siberia area – one of the most problematic objects of oil and gas production described in this article. Here is discussed geological substantiation and first result of new technology involving in drilling of Riphean carbonate reservoirs with "Controlled pressure technology" by recovery wells with horizontal bottom at the oil-gas condensate field in Evenki Region. Comparison results of conventional drilling and "MPD" (Managed Pressure Drilling) technology.
Riphean reservoirs drilling process could be provided in two options.
The first one – horizontal conventional drilling. As far as the bit penetrates into the reservoir we are seeing SPP (Stand Pipe Pressure) decrease which means we have total lost circulation. There was only one means for resolving this problem – using LCM (Lost Circulation Material). Due to complicated geology and high parameter of gas factor in Riphean reservoirs (losses while circulation/ gains while static), LCM was insufficient solution.
The second is to perform drilling process using MPD (Managed Pressure Drilling) technology. We have the advantage using lower mud weight compared with conventional drilling. MPD technology corresponds with geological conditions of Riphean reservoirs and can be more profitable in future production from these wells.
MPD technology with closed loop circulation system showed that we can "manage" BHP (Bottom Hole Pressure) and it really works in temperature conditions of 45 Celsius below zero in Evenki Region (East Siberia). In practice we have seen, that it was possible to achieve more gentle management of BHP than with conventional drilling using LCM. Also with "MPD" system in this oilfield we were able to drill the first ERD (Extended Reach Drilling) well. However, even with such extended horizontal section (1000 meters), a significant reduction of losses was achieved without using LCM. Total results of MPD technology we will see after DST (Drill Stem Test) of drilled wells.
New technology showed that it was a right choice to use close loop system and MPD. Also for drilling new wells in this Riphean carbonate reservoirs of this oilfield area we will use this experience. Best way to reduce catastrophic losses in abnormally low pressure reservoir conditions is reduce and control the ECD and details how to achieve it we have considered in this article.
The results: Reduced interval construction time. From 31 days to 24 days. Reduced fluid loss during drilling. From 2000 m3 to 1200 m3. Improved the operational safety by closing the loop and real time early kick and loss detection.
Reduced interval construction time. From 31 days to 24 days.
Reduced fluid loss during drilling. From 2000 m3 to 1200 m3.
Improved the operational safety by closing the loop and real time early kick and loss detection.
Eaton, Ammon N. (Brigham Young University) | Beal, Logan D. R. (Brigham Young University) | Thorpe, Sam D. (Brigham Young University) | Janis, Ethan H. (Brigham Young University) | Hubbell, Casey (Brigham Young University) | Hedengren, John D. (Brigham Young University) | Nybø, Roar (SINTEF) | Aghito, Manuel (SINTEF) | Bjørkevoll, Knut (SINTEF) | Boubsi, Rachid El (Huisman Well Technology) | Braaksma, Jelmer (Huisman Well Technology) | van Og, Geertjan (Huisman Well Technology)
For automation of managed pressure drilling (MPD) to succeed, the automation system needs access to accurate measurement data and the ability to translate this into a correct representation of reality in the well. However, inaccuracies due to calibration problems and errors or omissions in manually entered data may combine with spurious behavior in the control model to make the automation system unreliable. This study presents a novel control scheme for automated MPD that addresses the problem of model reliability by using multiple control models to provide optimal control moves, even with the failure of one or two models.
This work simulates the ability to optimize MPD operations with realistic measurement signals using Model Predictive Control (MPC) with a range of model types. Further, it provides a robust automated MPD system to reduce interruptions to drilling operations. This work makes use of a high fidelity dynamic well bore model in addition to low order and empirical control models. The three controllers feed into a switch that selects the best available controller recommendation and allows for a seamless transition between controllers. The switch control scheme enables automated switching between the controllers in the event of one or two models failing and also allows for the tuning and troubleshooting of one model while the others continue to run, all without any interruption to the drilling process.
One of the key innovations in the ensemble switch is the seamless transition between controllers. This is accomplished by using the current process manipulated variable values as initial values for the optimization routines in the model predictive controllers that are not actively used to control the well. The strategy is tested in common drilling situations.
Two typical drilling scenarios are simulated: normal drilling operations and a pipe connection procedure. The validity of the novel control structure in each scenario is verified through simulated outliers, drift, and noise, as well as simulated controller failure and lack of optimal solution convergence. The controller is able to maintain bit pressure within +/- 1 bar of the 400 bar set point during normal drilling operations despite temporary signal loss and poor data quality. Also, the bit pressure is held within +/- 5 bar of the 340 bar set point during a pipe connection procedure with no bit pressure measurements available to the controller.
The techniques presented here can be used for more robust and stable automated MPD. Moreover, multiple models provide benefits that are typically associated with improved reliability due to hardware and safety systems redundancy allowing drilling to continue with fewer interruptions.
Aneru, Suleman Ali (University of Port Harcourt) | Dosunmu, Adewale (University of Port Harcourt) | Anyanwu, Chimaroke (University of Port Harcourt) | Ekeinde, Evelyn (University of Port Harcourt) | Odagme, Barodor (University of Port Harcourt)
Managed Pressure Drilling (MPD) as a drilling technique is the result of the high costs of nonproductive time (NPT) caused by close proximity between formation pore pressures and fracture pressures which is common to offshore/deep-offshore, HPHT and depleted reservoirs as well as some land drilling operations. The optimization of the Constant Bottom Hole Pressure (CBHP) variation of MPD was studied in this work. The CBHP generally refers to the term used to describe actions taken to correct or reduce the effect of circulating friction loss or equivalent circulating density (ECD) in an effort to stay within the limits imposed by the pore pressure and fracture pressure. In this work, a computer program was designed to efficiently calculate the required back pressure term needed to maintain the BHP constant between the pore pressure and the fracture pressure. The computer software designed was used to determine the back pressure for both offshore and onshore wells at various depths to verify the robustness of the software and its level of accuracy. The economic impact of the work was also analyzed in respect to reduction of the general cost associated with the NPT during drilling operations both onshore and offshore.
A variety of Wellbore Strengthening (WBS) methods have been introduced and successfully applied in the field drilling practices over the last decade, with origins going back as early as the late 1980’s. In addition, a beneficial casing “smear” effect (CSE) has been observed in recent years during drilling with casing (DWC) operations, preventing lost circulation even when drilling highly depleted formations. CSE mimics WBS effects observed during regular drilling operations in its ability to effectively extend fracture gradients and prevent lost circulation, which is of great benefit to drilling difficult wells with tight drilling margins such as (ultra-)deepwater wells. In fact, when used appropriately, WBS and CSE may offer well construction benefits that are on par with those of managed pressure drilling (MPD) and dual gradient drilling (DGD), at reduced equipment usage, complexity and cost. To explain WBS and CSE phenomena, a variety of different mechanisms have been proposed. These broadly fall into three categories: (1) Wellbore Face Sealing (WFS) - forming a uniform seal around the wellbore that prevents fluid leak-off and interferes with fracturing; (2) Wellbore Stress Augmentation (WSA) - augmenting the closure stress around the wellbore by propping open induced fractures either at the wellbore face or somewhere into the fracture; (3) Fracture Propagation Resistance (FPR) - effective solids plugging of any fracture tip, thereby interfering with effective fracture growth. In the proposed paper, we offer a re-examination of previously published data (such as open-hole leak-off tests) and theoretical results, and present our own independent results and assessments to show that WBS and CSE have a common, unified origin. It will be shown that the only mechanism that explains all the data obtained to date is, in fact, the FPR mechanism. Moreover, guidelines will be presented to exploit FPR optimally for the benefit of future complex well construction, such as ultra-deepwater wells with tight drilling margins.