Ozyurtkan, Mustafa Hakan (Istanbul Technical University) | Altun, Gursat (Istanbul Technical University) | Ettehadi Osgouei, Ali (Istanbul Technical University) | Aydilsiz, Eda (Istanbul Technical University)
Static filtration of drilling fluids has long been recognized as an important parameter for drilling operations. Since the standard laboratory testing procedures only consider static conditions, the filtration and cake properties under continuous circulation and dynamic borehole conditions are not usually well determined. Therefore, the measurement of dynamic filtration is particularly important in order to mimic actual downhole conditions.
An experimental study has been carried out by the ITU/PNGE research group to characterize the dynamic filtration properties of clay based drilling fluids. This study is an impressive attempt to figure out the dynamic filtration phenomena of clay based muds. The experimental results obtained from a dynamic filtration apparatus (Fann Model 90) are reported in this study.
Bentonite and sepiolite clays based muds formulated with commercial additives have been investigated throughout the study. Numerous dynamic filtration histories with test duration of 45 to 60 minutes at temperature conditions ranging from 150 to 400 oF, and a differential pressure of 100 psi have been applied to muds. Three key parameters namely spurt loss volume, dynamic filtration rate (DFR), and cake deposition index (CDI) have been determined to characterize the dynamic filtration properties of mud samples.
Results have revealed that bentonite based muds have better dynamic filtration properties than those of sepiolite muds at temperatures up to 250 oF. However, they have lost their stability over 250 oF. Furthermore, formulated sepiolite based muds have remarkable dynamic filtration rates and cake depositions above 300 oF. To sum up, the experimental results of this study point out that sepiolite based muds might be a good alternative to drill wells experiencing high temperatures, particularly in deep oil, gas and geothermal wells.
Fracture ballooning usually occurs in naturally fractured reservoirs and is often mistakenly regarded as an influx of formation fluid, which may lead to misdiagnosed results in costly operations. In order to treat this phenomenon and to distinguish it from conventional losses or kicks, several mechanisms and models have been developed. Among these mechanisms under which borehole ballooning in naturally fractured reservoirs take place, opening/closing of natural fractures plays a dominant role. In this study a mathematical model is developed for mud invasion through an arbitrarily inclined, deformable, rectangular fracture with a limited extension. A governing equation is derived based on equations of change and lubrication approximation theory (Reynolds’s Equation). The equation is then solved numerically using finite difference method. Considering an exponential pressure-aperture deformation law and a yield-power-law fluid rheology has made this model more general and much closer to the reality than the previous ones. Describing fluid rheology with yield-power-law model makes the governing equation a versatile model because it includes various types of drilling mud rheology, i.e., Newtonian fluids, Bingham-plastic fluids, power-law, and yield-power-law rheological models. Sensitivity analysis on some parameters related to the physical properties of the fracture shows how fracture extension, aspect ratio and length, and location of wellbore can influence fracture ballooning. The proposed model can also be useful for minimizing the amount of mud loss by understanding the effect of fracture mechanical parameters on the ballooning, and for predicting rate of mud loss at different formation pressures.
The demand for hydrocarbons is expected to grow worldwide. As a result, deeper reservoirs are being explored. Emulsified acid systems are preferred for the stimulation of high-temperature carbonate reservoirs with bottomhole temperatures (BHTs) of 275°F and above. The retarded nature of an emulsified acid system decreases both the acid reaction rate and the rate of corrosion. However, the lack of emulsion stability of these systems is a major problem associated with high-temperature applications (at 300°F and above).
Corrosion inhibitors and intensifiers can interfere with the stability of an emulsified acid system, which consequently leads to higher corrosion losses. At the same time, there is a need for better inhibition systems to counteract the effects of corrosion at higher temperatures. In this paper, a combination of three intensifiers was used, based on the differences in their mechanisms for inhibitor intensification action. The study includes the effect of varying the concentration of each component, hydrochloric (HCl) acid strength (20 to 28%), and temperature (275 to 325°F) on the stability and corrosion rate using P-110/N-80 coupons. The unique combination of the corrosion inhibitor and three intensifiers with proper optimization created a system capable of passing a corrosion test at 300°F using 28% HCl acid. The temperature limit of the system can be extended up to 325°F using an additional intensifier with 25% acid strength.
The present system can be used for acid stimulation of carbonate reservoirs with BHTs up to 325°F. This study revealed a better understanding of the effect of the intensifiers in an emulsified acid system and the synergism amongst them. This enabled the use of an emulsified acid stimulation on carbonate reservoirs having BHTs up to 325°F while reducing the corrosion rate to a level that meets the current market demand for acidizing operations. This work shows that emulsified acid systems can be used with HCl acid strengths ranging from 20 to 28% at high temperatures. The resultant better wormholing at high temperatures should also lead to enhanced oil production.
Jadoon, M. Saeed Khan (Oil and Gas Development Company Limited) | Majeed, Arshad (Oil and Gas Development Company Limited) | Bhatti, Abid Husain (Oil and Gas Development Company Limited) | Akram, Mian M. (Oil and Gas Development Company Limited) | Saqi, Muhammad Ishaq (Pakistan Petroleum Limited)
Balanced drilling through naturally fractured reservoir and controlling loss for preventing reservoir damage and rehabilitation of normal production is a serious challenge in the Kohat-Potwar basin of Pakistan. The potential of hydrocarbons in these reservoir rocks has been masked by the overbalance drilling practices in this region. Due to overbalance drilling in fractured reservoirs and the use of heavy mud with barite blocks the fractures and that results in little or no flow during DST. The negative results of DSTs usually force the decision makers either to abandon the well or to re-test and establish the connectivity between the formation and the well bore.
The well under study was drilled in fractured carbonate reservoir rock to a depth of more than 5000 meters in Kohat-Potwar basin to target Datta and Lockhart formations. During drilling, due to complexities, well could not reach the Datta formation. No wire line and image logs could be obtained in Lockhart formation due to slim hole. The last 5-7/8 inch hole of this well had to be drilled by using Oil Based Mud (OBM) to control well bore instability, the same mud was used in the reservoir sections. During drilling, losses were observed in the reservoir section. On the basis of drilling information, the well was directly completed in the Lockhart formation. After completion, well was allowed to flow but no hydrocarbon surfaced. As Lockhart formation is proven producer, and it became a challenge to evaluate the reservoir for its production potential and to find out the causes of no flow from the formation.
After negative results of well test, all the data of G & G and mud logging was reviewed and detailed analysis of fractures network over the field were carried out to understand the well behavior. The data revealed that mud losses during drilling are i ndicative of fracture's presence in the tested zone(s) and fractures may have been plugged resulting in no flow during test. It was realized that reservoir has potential but connectivity between formation and the well bore need to be enhanced. Even after no flow during initial testing of the well for long period, bold decision of cleaning of the well was under taken and series of Nitrogen kick off jobs were undertaken to facilitate the well to flow. The nitrogen kick off were continued for four months, longest cleaning job ever undertaken in Pakistan and close monitoring of well was put inplace. After four months, WHFP started improving and flow of the hydrocarbons was observed and finally 730 bbl/d of oil and 1.6MMscfdgas were recorded. After the flow of the well, stimulation, with special recipe after lab experiments for OBM, was carried out with very encouraging results. After producing about one year, the well is still cleaning under natural flow.
In this paper, we would try to share our experiences about the use of OBM in fractured carbonate reservoirs, fracture characterization, reservoir damage and its remedial jobs. In addition to this, well performance, well cleaning and stimulation methodology, evaluation of non-flow behavior of well during initial testing and the lessons learned to transform failure to success will be explained.
Ilyas, Muhammad (Mari Gas Company Limited) | Sadiq, Nauman (Dowell Schlumberger Western S.A.) | Mughal, Muhammad Ali (Mari Gas Company Limited) | Pardawalla, Hassan (Dowell Schlumberger Western S.A.) | Noor, Sameer Mustafa (Dowell Schlumberger Western S.A.)
This research work "Improvement of Cementing in Deep Wells" was carried out with the collaboration of Mari Gas Company Limited (MGCL), Pakistan and Schlumberger Pakistan, to recommend the designs and practices by which future cementing operations for zonal isolation in deep Wells may be improved.
Mari Gas Company Limited had successfully drilled, tested and completed Halini Well - 1 (Total Depth = 5350 m) in the Karak Block. The Karak Block is located in Northern Region of Pakistan which is known for its challenges, such as high pressure water influxes and weak zones, which led to a number of cementing challenges in this Well. The Cementing related problems that were faced on this Well were:
1- Sustained Casing Annulus Pressure in 13 3/8" x 9 5/8" Casing Annulus
2- Poor CBL-VDL results in 13 3/8" and 9 5/8" Casing
The scope of the project was to investigate the root cause of cementing challenges faced at Halini Well-1 and to propose recommendations for improving future cementing in deep Wells.
s to the above, the cementing of Halini Well- 1 was thoroughly analyzed along with similar case histories and problems in offset fields. On the basis of observations made, various recommendations have been proposed, mostly related to areas of fluid rheology, fluid contamination, fluid channeling, density and friction pressure hierarchy between fluids, fluid loss, temperature differential, and setting of casing slips etc. The idea for this project is to serve as a guideline for cementing the future deep Wells.
Primary Cementing is the process of placing cement between casing and the formations exposed to wellbore . The objective is to provide Zonal Isolation by creating a hydraulic seal thereby preventing the flow of wellbore fluids like oil, water or gas between formations or to surface. The life of the Well is directly dependent on the quality of this hydraulic seal, making cementing job a vital operation.
Incomplete zonal isolation can prevent either the Well from being completed at all to a loss of a producing well. The importance of cementing operation can be magnified by the fact that the cement has to survive the complete life of the Well that could vary anywhere between a year to fifty or more years.
Successful cementing operation would include a good casing to cement bond, good cement to formation bond and the ability of the cement placed itself to prevent any flow through it. In the event of this hydraulic seal being ineffective, it can allow fluids to migrate and channel through in the annulus and potentially even flow to the surface. This destroys the integrity of the Well. Any remedial job is extremely difficult to plan, execute and usually carries very low chances of success.
The Schoonebeek heavy-oil field was first developed by Nederlandse Aardolie Maatschappij B.V. (NAM) in the late 1940s. Because of economics, it was abandoned in 1996. In 2008, the Schoonebeek Redevelopment Project, using a gravity-assistedsteamflood (GASF) design concept, was initiated with 73 wells (44 producers, 25 injectors, and 4 observation wells). Steam injection and cool-down cycles subject a cement sheath to some of the most severe load conditions in the industry. Wellbore thermal modeling predicted that surface and production sections would experience temperatures in excess of 285°C (545°F) and considerable stress across weak formations. A key design requirement was long-term integrity of the cement sheath over an expected 25- to 30-year field life span. Complicating this requirement was the need for lightweight cementing systems, because lost-circulation issues were expected in both hole sections, particularly in the mechanically weak Bentheim sandstone. The long-term integrity challenge was divided into chemical and mechanical elements. Prior research on high-temperature cement performance by the operator provided necessary guidance for this project. Laboratory mechanical and analytical tests were conducted to confirm the high-temperature stability of the chosen design. In addition to using lightweight components, foaming the slurry allowed the density, mechanical, and economic targets to be met. A standardized logistical plan was put in place to allow use of the same base blend for the entire well, adjusted as needed, using liquid additives, and applying the foaming process when necessary. This single-blend approach greatly simplified bulk-handling logistics, allowing use of dedicated bulk-handling equipment. The first well was constructed in January 2009; all 73 wells have been successfully cemented to surface. The steaming process, initiated in May 2011, has progressed with no well integrity issues to date.
This paper summarizes 10 years of experiences on pumping cement through bottomhole drilling assemblies - BHAs. Despite a lot of industrial skepticism, a total of 79 cement jobs have been performed through a variety of drilling assemblies, in 3 categories of job types:
i) Curing critical mud losses to restore well control
ii) Plugging back pilot holes
iii) Planned plug or squeeze jobs
The job objectives were met for all the cement jobs performed, and high risk well control situations were resolved. The cementing operations have been performed from different types of offshore installations, like fixed platforms, semi-submersible rigs, as well as from TLP's - Tension Leg Platforms.
Most significantly, critical mud losses have been cured by pumping totally 13 cement jobs through rotary steerable drilling assemblies. Losses were cured and well control restored by performing jobs mainly through 8 ½?? - and 12 ¼?? drilling assemblies. The most severe case handled HPHT conditions and cesium formate drilling fluid.
By taking a controlled risk, the total well risk is significantly reduced. Time and huge costs are saved by performing cement jobs that are instinctively considered as a threat to well control. By planning these cement jobs carefully, the total risk of performing the operation through the bottom hole assembly is reduced.
After gaining experience from some severe, un-planned lost circulation incidents, a best practice was developed and implemented in order to be better prepared, especially for the un-planned events. The same procedures have also been implemented in the planning phase of drilling operations and some cementing operations are planned and executed this way.
Al Shamsi, Juma Suleiman (Abu Dhabi Co. Onshore Oil Opn.) | Al-menhali, Adnan Mohammed (Abu Dhabi Co. Onshore Oil Opn.) | Hamdy, Ibrahim Thanaa Eldin (ADCO) | Parkinson, Andrew (Abu Dhabi Co. Onshore Oil Opn.) | Kuyken, Chris
Extended reach drilling (ERD) represents one of the industry's most impressive engineering accomplishments in terms of wellbore construction. As the recovery of oil and gas becomes more complex, these wells have pushed drilling engineering boundaries to new limits to meet the world's demands in the safest, most environmentally conscious and cost effective manner. Drilling ERD wells requires the latest innovations in drilling engineering principles; such wells are more interrelated and sensitive to smaller changes than conventional wells. An integrated approach for both planning and execution becomes more critical due to the high operational risks and all uncertainties must be properly assessed by solid engineering planning. In addition to that, it brings engineering challenges from many disciplines, which must be met and addressed for proper execution. Integration of drilling and real time evaluation allows engineers and geoscientists to take the proper drilling decisions and lead to reduce operational risk. It will also provide an accurate well placement; improve drilling efficiency and maximum recovery.
Well-1 & Well-2 were the latest ERD wells drilled in Abu Dhabi. Abu Dhabi Company for Onshore Oil Operations (ADCO) has drawn on extensive experience from numerous ERD Projects around the world, successful engineering tools and proper assessment for the several of challenges of those projects. In addition to the positive contribution from National Drilling Company (NDC) in providing all the necessities in terms of equipment and support which enabled the land rig to drill the well Well-1 to a total depth of 19,725 ft MD with a horizontal displacement (HD) of 10,131 ft. In addition, Well-2 was drilled to a total depth of 20,003 ft MD with a horizontal displacement of 10,303 ft, which was a bench mark record in the United Arab Emirates (UAE). The numerous challenges faced on those two wells in terms of planning and the rich experience gained from successfully executing such wells are all highlighted in the attached paper.
Jasem Al-Saeedi, Mohammed (Kuwait Oil Company) | Al Fayez, Fayez Abdulrahman (Kuwait Oil Company) | Rasheed Al Enezi, Dakhil (Kuwait Oil Company) | Al-Mudhaf, Mishary N. (Kuwait Oil Company) | Sounderrajan, Mahesh (Kuwait Oil Company) | Subash, Jaikumar (Kuwait Oil Company)
Drilling activities have increased in the State of Kuwait to enable the production of more gas from the Jurassic formations. The wells drilled to these prospects are challenging because of HPHT conditions, sour reservoir fluids and narrow drilling window.
Only vertical and deviated wells have been drilled to date, and in order to augment the production requirements horizontal wells were planned. For effective development of these reservoirs, horizontal well profiles were planned to increase the ability of the wells to access a permeable interconnected vertical fracture network which could result in high productivity and reserve recovery.
After detailed study, well SA-297 was selected as an appropriate candidate for a horizontal pilot project. In this pilot, the objective was to drill the first horizontal well through the Najmah reservoir in the North Kuwait fields. The project, being the first of its kind, posed many challenges. These included: drilling and casing 16?? hole at 60º well trajectory to 13,500 ft.; drilling the salt-anhydrite high pressure Gotnia at 60º inclination; drilling a slim pilot hole in the reservoir with K-formate WBM to facilitate positioning of the lateral; plug back this pilot hole and execution of a high DLS sidetrack just below 10 3/4" shoe; casing off formations with borehole stability concerns; drilling 6?? lateral hole by geo-steering; tubing plugging concerns during DST testing
Due to plugging of the tubing during testing, an intervention job was carried out with a workover rig to clear the tubing with coiled tubing in a live well and subsequently retrieve DST tools. This was a unique job carried out for the first time in Kuwait.
This paper will give details on the well construction, the complexities in the drilling operations and technical challenges faced while drilling the directional trajectory and in the special workover operations.
Martinez, Erik (Halliburton) | Ramirez, Silvestre (Pemex E&P) | Ramirez Lara, Ricardo (Pemex E&P) | Alvarez Lopez, Eduardo (Pemex E&P) | Bevilacqua, Simon (Halliburton) | Barrera, Guillermo (Halliburton)
The Bolontiku field is located offshore on the continental shelf of the Gulf of Mexico, adjacent to the coast of Tabasco state. This field is composed of dolomitized carbonates of the Upper Jurassic Kimmeridgian formations, which yields 39° API hydrocarbons. Exploitation has dropped the bottomhole pressures from 8,159 psi to 5,600 psi and has created an average operating drilling window of 0.07 g/cm3. Such a narrow operating window increases the technical difficulty for continued development in this mature field using conventional drilling techniques. The complexity of effectively controlling the wellbore pressure has resulted in an endless cycle of fluid loss to formation, kicks, and well control events that translate into non-productive time (NPT), which increased operating time and costs, potentially leading to well abandonment.
A managed pressure drilling (MPD) technique allows for effective control of the pressure profile throughout the wellbore, identifying the bottomhole pressure (BHP) limits and applying appropriate backpressure accordingly. Owing to its efficiency, this technique has evolved from an innovative technology to become a required application to mitigate the inherent wellbore pressure problems associated with conventional drilling. Therefore, as MPD evolves, different approaches for well control evolve for kick events.
This paper describes a well-control application simultaneous to the drilling operation using MPD with a closed-loop pressurized control system. This paper reviews a case history of two wells that were drilled with MPD and compares results against three wells that were conventionally drilled in the Bolontiku field. MPD and simultaneous well control allowed for drilling the Bolontiku 37 well, which consisted of compartmentalized pressure that historically lead to fluid losses and water influxes. Therefore, it was possible to drill through zones that before were not technically possible.