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.
Malik, Saeed Aslam (Oil & Gas Development Company Limited) | Channa, Munsif Hussain (Oil & Gas Development Company Limited) | Majeed, Arshad (Oil & Gas Development Company Limited) | Latif, Muhammad Khalid (Oil & Gas Development Company Limited) | Asrar, Muhammad (Weatherford)
During this period of energy crisis in Pakistan every effort is being made to produce every molecule of subsurface hydrocarbons. Particularly, the gas reservoirs which were not brought on production, due to low well deliverability or lack of required technology in the past are being explored and exploited. These include Tight, Low BTU, Sour and Acidic gas reservoirs. Such reservoirs pose specific problems related to drilling, production and development aspects.
This paper depicts drilling and testing of a reservoir which is above sea level and its initial reservoir pressure is approximately 1000 psi below the normal hydrostatic pressure. It is one of the lowest pressure reservoirs of the world which has been drilled with successful flow of gas. Underbalance drilling technology was chosen to drill this challenging reservoir. Primary objective of under balance Drilling (UBD) was to establish reservoir potential by acquiring virgin reservoir characteristics.
Historically, three wells have been drilled to test this reservoir. First two wells were drilled using conventional drilling methodology, both the wells experienced heavy mud loses during drilling and it was difficult to evaluate the production potential of this low pressure reservoir. Afterwards, pay zone of SML in third well X #02 was drilled and tested using Underbalance Drilling technique.
This paper further describes the problems faced by the operator to drill first two wells in terms of mud losses and evaluation of production potential of low pressure reservoir of SML. In conclusion, it was a successful application which happened due to exceptional team work from all project parties. This application has opened new horizons of exploration and production of such reservoirs particularly in Baluchistan and generally in Pakistan.
INTRODUCTION AND BACKGROUND
The E.L of interest is located in Baluchistan province of Pakistan. First well Y # 01 was drilled by another operator back in 1953-54 to depth of 1947 M. This well experienced severe mud losses against carbonates of Habib Rahi (HRL) and Sui Main Limestone (SML), and other down hole problems. Drill Stem tests in SML flowed to maximum of 3 MMSCFD of gas at BHP of 279 Psi. This gas rate was observed after re-perforations, pumping acids and swabbing for many days.
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.
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.
Understanding the properties of formation fluid is a critical step in reservoir characterization. The use of Logging While Drilling (LWD) based fluid sampling becomes increasingly important in high risk scenarios. The LWD environment is significantly different from that of Wireline (WL) for sampling operations as the dynamic filtrate invasion is still in effect. LWD sampling is a relatively new technology and its sampling efficiency compared to WL sampling is not well known. This study aims to understand the effects of dynamic invasion processes on LWD fluid sampling and compare its performance with WL based fluid sampling. The results of the simulation study performed revealed that when the wait time after the drilling is optimized, LWD can provide cleaner samples in shorter cleanup time than WL sampling. It also revealed that the reservoir fluid breakthrough time would be shorter in LWD sampling compared to that of WL. This study indicates that with proper modeling, an optimized sampling program can be executed to meet the objectives of the LWD sampling operations in the most economic manner.
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.
This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 156992, "Novel Nanoparticle-Based Drilling Fluid With Improved Characteristics," by Mohammad F. Zakaria, Maen Husein, and Geir Hareland, SPE, University of Calgary, prepared for the 2012 SPE International Oilfield Nanotechnology Conference and Exhibition, Noordwijk, The Netherlands, 12-14 June. The paper has not been peer reviewed.
This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 157031, "Application of Nanotechnology in Drilling Fluids," by Katherine Price Hoelscher, SPE, Guido De Stefano, SPE, Meghan Riley, SPE, and Steve Young, SPE, M-I SWACO, prepared for the 2012 SPE International Oilfield Nanotechnology Conference and Exhibition, Noordwijk, The Netherlands, 12-14 June. The paper has not been peer reviewed.
One of the greatest challenges with respect to coal seam gas (CSG) wells in Queensland, Australia is the many loss zones encountered during drilling and cementing operations. Typical directional wells in the area are up to 2000 m measured depth (MD) and 1200 m true vertical depth (TVD). In some instances production enhancement by fracture stimulation is required and therefore high-strength cement is necessary while maintaining the lowest possible pressure on the formation and natural fractures.
A trial was setup on a directional well pad where various methods of returning cement to surface were attempted. All three wells had similar well design, expected losses, and drilling times. The first well was unsuccessful and no cement was returned back inside the previous surface casing shoe. With the addition of a reactive spacer and more excess volume, cement inside the previous casing shoe was achieved on the second well. Both wells used standard 12-lbm/gal slurries. The third and final well on the pad required a step-change in the cement job design to achieve cement to surface.
The most successful cementing job was achieved on the third well by redesigning the slurry to a lower density of 11 lbm/gal, without compromising set times, thixotropic properties, and high compressive strength. To improve equivalent circulating densities (ECD), the new slurry was designed with lower rheology. The slurry's low solids-to-water ratio (SWR) and large slurry volume, which precluded batch mixing, required the job to be mixed and pumped on-the-fly using an automated volumetric mixing system rather than using density mixing.
This paper discusses the job preparation and technical details involving how the 11-lbm/gal cement slurry achieved a successful production casing cement job with returns to surface. With similar successes demonstrated on subsequent wells, this case history set a new standard in the field.