Bahuguna, Ajay (Oil & Natural Gas Corp. Ltd.) | Ahmed, Ramy (Schlumberger) | Ahmed, Mohamed Elbadri (Schlumberger) | Vazquez, Maria Leticia (Schlumberger Logelco, Inc) | Shaheen, Tarek | Sutrisno, Hermawan Joko
Munga field of the Greater Nile Petroleum Operating Company (GNPOC) in Sudan has several wells that have commingle production from the Aradeiba, Bentiu-1 and Bentiu-2 formations. These formations are highly variable in terms of the reservoir properties, oil types and pressure regimes. Because of the contrast properties of different layers, the water cut phenomenon is relatively fast and severe which hampers the productivity and ultimate recovery of the individual well as well as the field.
For effective Reservoir Management and to limit the declining trend of the field, Water Management Techniques are applied in some of the wells of this field. Information obtained in the process was used for reservoir model calibration, well productivity prediction, low productivity diagnosis, and generation of new drainage points and remedial action for water management.
This paper discusses the technical details of three cases corresponding to the wells Munga-XX and Umm Sagura South-XX (USS-XX) and Munga-XY in which, a multidisciplinary approach has been implemented in order to determine depletion profile, produced oil and remaining reserves, locate any "by-passed?? oil zones, determine oil and water contributions from each zone and shut off the excess water production while maintaining or increasing oil production.
The source of water entry was identified in multi-rate production logging using Production Services Platform and electrical probes through Y tool-ESP completion. Vx meter was carried out at surface to real time monitoring the well production during the production logging survey. The well depletion profile was determined using Cased Hole Formation Resistivity (CHFR*) tool. A multidisciplinary team processed and interpreted the logging data and based on the results remedial jobs were carried out
The general outcome of the remedial jobs based on this approach was a considerable reduction in water production in both Munga-XX and USS-XX wells as well as oil production gain, making this a successful job.
Exploration and development of Heavy oil fields with high water cut and sand production in Muglad basin in Northern Africa started with vertical wells and as time progressed matured into drilling Horizontal wells.
Typically drilling challenges in this area include drilling very reactive shales , shallow kick off depths and high build rates, unconsolidated sand stones interbedded with shales which are sensitive to mud weight and are prone to lost circulation.
First few horizontal wells were drilled with conventional technology of positive displacement motor with silicate mud. Many of these wells faced hole cleaning issues leading to pack off ,excessive back reaming and stuck pipe incidences.Uneven build rates via sliding in interbedded formation leading to high borehole tortuosity . It is significant to note that due to these difficulties one of the planned horizontal wells was side tracked three times after stuck pipe incidences and finally completed as a 30 degree deviated well with a total cost over run of 300% above AFE.
Since then Rotary steerable system has been deployed to drill these challenging wells with significant improvement in drilling performance ,saving days and cost and eliminating stuck pipe incidences. This paper compares the performances of drilling with PDM Vs RSS in the same reservoir and presents the lessons learnt. A cost benefit analysis has also been performed and it clearly shows that RSS is both technically and economically a sound approach to drilling horizontal wells in Muglad basin.
Horizontal well drilling campaign in Sudan was started in 2004 with the following objectives:
• Increase well bore exposure to reservoir and hence increase the rate of production of heavy oil.
• Decrease the near well turbulence and hence decrease sand production.
• Decrease of Draw down pressure which will eventually lead to decrease in water cut.
The candidate wells were chosen in very well developed fields targeting by passed oil. Presence of good number of close by vertical offset wells offered good geological control for well placement. On the drilling front there were lots of challenges that were encountered while drilling the horizontal wells. In this paper we will look into the evolution of drilling techniques from the first well to the recent wells and see how continuous adoption of new and fit for purpose technology has minimized drilling risks and lead to economical drilling of horizontal wells.
Drilling Challenges in Muglad basin
Drilling of horizontal wells require in depth knowledge about the formations in the basin. Clear understanding of problems posed by the formations will go a long way in mitigating the drilling risks.
Figure 1 shows the formation stratigraphy of muglad basin Tendi and Nayil Formations are predominantly made up of water sensitive shale formations, which at times lead to bit and stabilizer balling. The next formation below is the Amal massive sandstone. Amal sand can be abrasive in some areas and usually have issues of lost circulation; build up of well bore deviation. Below Amal sand stone is Ghazal and Zarqa formations. These are made of consolidated sand shale intercalations and do not pose any major drilling problems. Aradeiba formation that lies beneath Zarqa can be sub divided into two major bodies, the upper and the lower Aradeiba shales. Both these formations are strong water sensitive and result in borehole instability, tight spots, pack off even while drilling vertical wells. The lower Aradeiba also has some sand stone reservoirs embedded between the shale bodies which contain some promising reserves. Bentiu reservoir is primarily a sandstone reservoir, which has very low pore pressure gradient. Differential sticking is one of the major concerns in this formation.
Copyright 2006, Society of Petroleum Engineers This paper was prepared for presentation at the 2006 SPE Asia Pacific Oil & Gas Conference and Exhibition held in Adelaide, Australia, 11-13 September 2006. This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Abstract Maximization of recovery from anisotropic small and medium size oil fields is a daunting task for operators. Development strategies and concepts implemented in large fields generally are not appropriate for small and medium size fields. Inappropriate strategies and methodologies of exploitation affect the overall recoveries and economics of the project. This is further complicated in tight, viscous and sand incursion prone formations. This paper discusses about number of small fields located in Muglad basin wherein oil accumulation is found in multiple layers of late cretaceous deposits. The formations are heterogeneous, unconsolidated with higher viscosity and strong aquifer support. Some formations are tighter too. Field performance is marred by exponential rise of water cut due to adverse mobility and lifting through ESP. Production is affected due to poor influx in tighter formations through conventional wells. This behavior is limiting the producing life of existing wells, resulting into decline in production and causing significant bypassed and undrained oil. Horizontal wells with state-of-art completion both in openhole and cased holed with suitable artificial lift techniques were considered as one of the IOR option for maximizing well productivity in these thinly bedded heavy oil field with objective for tapping the bypassed oil and delaying the water production while controlling the sand production. Lessons learnt and results of the well placement along with cost/production analysis will be presented. Production results to date have been remarkable with productivity improvement factor varying 3-4 folds compared to vertical wells.
Tewari, R.D. (GNPOC) | Raub, M.R.B.A. (GNPOC) | Omar, M.I. (QP) | Fenghan, B. (GNPOC) | Moris, M. (GNPOC) | Jelani, J. (PRSS) | Ramachandran, S. (AWT) | Fooks, A.L. (AWT) | Peden, J.M. (AWT) | Montague, Eamonn T. (Brunei Shell Petr. Sdn. Bhd.)
This paper describes the importance of well construction & well integrity and its relationship to reservoir management. Productivity enhancement studies in combination with reservoir simulation modeling on the Greater Heglig fields have revealed that well performances and production related problems were largely related to poorly designed wells and poor cementing practices. As a result, water channeling and cross flow across wellbore dominated true well performance characteristics contributing to very high water cuts in the majority of the producers in Greater Heglig fields. Separating the mechanically induced well behaviour from reservoir behaviour helped history matching the wells greatly, findings of which were subsequently validated during the study through running of ultra sonic imaging tool. The ultra sonic logging campaign proved the existence of channels, micro annuli's and cross flow across the wellbore causing a "water channeling phenomena" of up to 90% water cut across majority of the wells. As part of the productivity enhancement program for the Greater Heglig fields, a total of 23 sidetrack candidates have now been identified to capture the remaining developed reserves of ca. 30.0 MMstb, which will otherwise remain unproducible from the existing wellbore's. In addition to this, fit for purpose sidetrack well designs and construction together with good cementing practices will be required to ensure well integrity to improve reservoir management of the Greater Heglig fields.