Africa (Sub-Sahara) Kosmos Energy has made a significant deepwater gas discovery off Senegal. The Guembeul-1 well in the northern part of the St. Louis Offshore Profond license in 8,858 ft of water encountered 331 net ft of gas pay in two excellent-quality reservoirs, the company reported. The results demonstrate reservoir continuity and static pressure communication with the Tortue-1 well, which suggests a single gas accumulation. The mean gross resource estimate for the Greater Tortue complex has risen to 17 Tcf from 14 Tcf as a result of the Guembeul discovery, the company said. Kosmos, the operator, has a 60% interest in the well. Timis (30%) and Petrosen (10%) hold the remaining interest. In Salah Gas has started production from its Southern fields in Algeria.
Africa (Sub-Sahara) Petroceltic International said that the first of up to 24 new development wells planned in Algeria's Ain Tsila gas and condensate field was successful. The AT-10 well, situated about 2 miles from the AT-1 field discovery well, reached a total depth of 6,578 ft. Wireline logs indicated that the expected initial offtake rate would be comparable to the AT-1 and AT-8 wells, both of which test-flowed at more than 30 MMcf/D. Petroceltic is the operator with a 38.25% interest in the production-sharing contract that covers the Ain Tsila output. The remaining interests are held by Sonatrach (43.375%) and Enel (18.375%). Sonangol reported that it has found reserves in the Kwanza Basin of Angola that could total 2.2 billion BOE, including reserves in a block jointly owned with BP. Block 24, operated by BP, holds an estimated 280 million bbl of condensate and 8 Tcf of gas, totaling 1.7 billion BOE, Sonangol said in a statement seen by Reuters.
Farid, Syed Munib Ullah (Pakistan Petroleum Limited ) | Ahmed, Hassaan (Pakistan Petroleum Limited ) | Mallah, Sohail Ahmed (Pakistan Petroleum Limited ) | Khanam, Mehwish (Pakistan Petroleum Limited ) | Dhawan, Sandeep (WellPerform ApS )
HPHT well environments present design & operational challenges that could potentially translate into well failure with high consequences. Several risk elements can combine into a complex hazard causing serious threat to well design & integrity. Risk elements could be complex downhole environment, material deration, material incompatibility with the completion/packer fluids and other treatment fluids, metallurgy imbalances etc. This case study presents early life production tubing integrity failure highlighting gaps and suggestions to adopt an integrated risk mitigation approach.
A 5,700 m TVD keeper HPHT exploratory well was drilled in north of Pakistan with reservoir pressure, temperature exceeding 10,000 psi and 320oF respectively. Matrix acidizing was required to remove near wellbore damage in the targeted carbonate reservoir. Initial kick start stimulation efforts resulted in tubing-annulus communication indicating compromised CRA super 13CR completion string integrity. Workover followed wherein another early life completion string failure occurred. Consequently, comprehensive analysis was carried out to determine failure root causes using a systematic fault tree analysis approach.
Failure investigation consisted of two broad scopes: a) Scrutinize well design against established industry standards and best practices for HPHT wells and; b) Completion string material metallurgy tests to evaluate compatibilities with exposed well & treatment fluids, bottom hole environment and assessment of all possible risk scenarios that by itself or in combination with other risks could cause material failure. Further, detailed study work included describing bottom hole environment comprehensively, various types of corrosion risk assessments including evaluation of environment assisted cracking risks, acid inhibitor efficiency evaluation, completion/packer fluid selection, fluid compatibility assessment and fluid additives degradation at high temperatures. Mill manufacturing processes, susceptibility of CRA material passive layer because of austenite percentage were also looked-into. Based on systematic approach and extensive in-depth analysis, key observations were drawn. These observations were further investigated with material testing and possible root cause failure risk factors were arrived at. Conclusions were drawn highlighting primary and secondary failure root causes. A new basis of design and qualification protocols was proposed to mitigate various risks to ALARP.
Ashraf, Qasim (Weatherford International Ltd) | Khalid, Ali (Weatherford International Ltd) | Ali, Farhad (Weatherford International Ltd) | Luqman, Khurram (Weatherford International Ltd) | Mousa, Ayoub (Weatherford International Ltd) | Babar, Zaheer Uddin (Pakistan Petroleum Limited) | Hussam Uddin, Muhammad (Pakistan Petroleum Limited) | Ullah, Safi (Pakistan Petroleum Limited)
An operator has drilled more than 32 wells to date in Adhi field, a gas and condensate field in northern Pakistan. The majority of these wells produce from depleted sands and some also produce from limestone reservoirs. The wells range in depth between 8,366 and 11,483 ft (2,550 and 3,500 m).
The operator was in the process of drilling the 8 1/2-in. hole section with the least possible mud weight to minimize the overbalance across the lost-circulation-prone limestone formation. While drilling the section, an unexpected gas pocket was encountered and subsequently required an increase in mud weight. To further add to already challenging drilling conditions, a fault was expected in the middle of the section. This fault was expected to produce total losses. The resulting loss of hydrostatic head would have caused a troublesome well-control scenario.
The above conditions led to an inherently tight drilling window. The operator thus made precise management of wellbore pressures a prime objective. However in conventional drilling, relying on the mud weight and pumping rate for accurate management of wellbore pressures proves highly inefficient, if not impossible.
A managed pressure drilling (MPD) and underbalanced drilling (UBD) hybridized system was devised to enable drilling the 8 1/2-in. hole section. An MPD system that applies constant bottom hole pressure would enable drilling the section with the least possible mud weight and as close as possible to the pore pressure line. In the event that heavy to total losses were encountered because of the predicted fault, the system could be switched over to UBD flow drilling. By switching over to UBD, the equivalent circulating density (ECD) would be reduced further and allow the well to flow while drilling and mitigating losses.
An MPD and UBD system was also expected to offer numerous benefits in drilling, including reduced chances of differential sticking, reduced formation damage, increased rate of penetration and bit life, less washouts in the drillstring and pumps, reduced nonproductive time, and enhanced abilities to execute well control with the pipe in motion without fear of getting stuck.
The MPD and UBD hybrid system was deployed to the location. The operator was able to drill the 8 1/2- in. section to the target depth. The operator commenced drilling with an MPD system but, as expected, heavy losses were encountered. Drilling then proceeded with UB flow drilling until reaching target depth. The hybrid system enabled the operator to achieve target depth, eliminate an entire casing string, and substantially reduce NPT. This paper discusses the planning, design, and execution of the MPD and UBD hybrid system.
The economic success of shale gas plays depends expansively on the brittle-ductile behavior of shale rock. The key parameter that separates the unconventional resources from conventional resources is the formation permeability, so all shale reservoirs need to be hydraulically fractured. Successful hydraulic fracturing requires targeting the most brittle rocks, therefore it is worthwhile to classify the shale in terms of brittle, less brittle, less ductile, and ductile zones. To identify the brittle-ductile transitional zone in shale reservoir, we have correlated the mineralogy-based brittleness index to elastic parameters estimated from well logs. The petrophysical model of the study area were plotted to break a story between brittle mineral contents, organic matter, brittleness indices and pore pressure to differentiate the brittle, ductile and transitional zones. Our results show that change in rock minerals distribution and brittleness index follow the trend in TOC, in less brittle to less ductile zone. In addition, we plotted the data in the crossplot of Young's modulus and Poisson's ratio and λρ-μρ lithology templates, noticed that shale with high quartz and high clay contents fall in less ductile to less brittle zone while shale with high quartz and low clay contents fall in less brittle to brittle zone. The overall observations of our study will support the previous research idea by suggesting the zone of brittle-ductile transition to design the hydraulic fracturing.
For a successful shale gas play in a region, the following characteristics (last but not least) need to be considered before going to the exploitation: (a) organic richness (TOC), (b) brittleness, (c) thickness, (d) gas-in-place, (e) permeability, (f) mineralogy, (g) maturation (Ro%) and (h) pore pressure (i) pore geometry (Zhu et al. 2011). Among these characteristics, shale brittleness is more critical to identify the desirable fracturing intervals and propagation for successful shale gas play (Wang and Gale, 2009). Van Dam et al. (2002) also documented in their research that brittleness is an important property that controls the failure process.
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, Asad (MOL Pakistan Oil & Gas Co. B.V Islamabad-Pakistan) | Farooq, Umar (MOL Pakistan Oil & Gas Co. B.V Islamabad-Pakistan) | Ahmad, Jawad (MOL Pakistan Oil & Gas Co. B.V Islamabad-Pakistan) | Saleem, Omer (MOL Pakistan Oil & Gas Co. B.V Islamabad-Pakistan) | Palekar, Arshad Hussain (Schlumberger, Islamabad-Pakistan) | Ramzan, Muhammad (Schlumberger, Islamabad-Pakistan) | Siddiqui, Faraz Hassan (Schlumberger, Islamabad-Pakistan)