Plessis, Guillaume J. (National Oilwell Varco, NOV) | Uttecht, Amie (National Oilwell Varco, NOV) | Pink, Tony (National Oilwell Varco, NOV) | Hehn, Lucien (National Oilwell Varco, NOV) | Jellison, Michael J. (Sub Surface Tools) | Vinson, Barry (Sub Surface Tools)
Moving into the next decade, wells in the Middle East are becoming more challenging as the deeper and more complex plays are exploited. This environment will be challenging from a torsional and tensile loading standpoint, and will be dynamically very active. This type of environment combined with high levels of H2S calls for a new high grade of sour service pipe. The Middle East is also opening up to the idea of high speed telemetry and wired pipe economics that call for a long lasting pipe product.
When using sour service pipe that is traditionally limited to 105 KSI grades, even with an optimized string design, drillers sometimes have no other option than to sacrifice the margin of overpull, risking losing the well if fishing is unsuccessful. Alternatively, they can elect to use drill pipe, which is not suited for use in this corrosive environment, generally using API S135, with a risk of parting the string due to H2S embrittlement. To address these operational limitations, the pipe body, which is the drill pipe limiting member in tension, has to come with higher material strength and at the same time exhibit improved Sulfide Stress Cracking (SSC) resistance compared to API S135 grade.
A novel grade of drill pipe was developed over a period of two years that is the strongest sour service drill pipe the industry has to offer to date and gives drillers an extra 19% of tensile capacity with its 125 KSI material yield strength. This new grade has been ordered for use in various regions of the world and for numerous applications. At this time, it is being used for intervention and stimulation operations in the Gulf of Mexico (GOM), and drilling long, extended reach (ER) wells with wired telemetry drill pipe in the Middle East.
This paper presents the phases of the grade development and discusses testing requirements for the crossover between strength and SSC resistance. It also includes statistical data on the first full scale manufacturing tests. Finally, it outlines the products expectations for field applications.
Yong, Huang (China University of Petroleum) | Lihong, Zhu (China University of Petroleum) | Deyong, Zou (China University of Petroleum) | Hualin, Liao (China University of Petroleum) | Jinying, Wang (China University of Petroleum) | Jinshen, Yan (China University of Petroleum) | Yugang, Zhou (China University of Petroleum) | Zhibin, Wang (China University of Petroleum)
The hollow-through DTH hammer reverse circulation continuous coring drilling technology has been successfully applied to well drilling. During its application, reverse circulation drilling sometimes does not work in broken formation or under leakage formation condition. Difficulty in sampling is another problem. These problems are primarily caused by the injected gas. It comes into the fissures and not drives the reverse circulation, thereby failing to generate an adequate pressure at the hole bottom to deliver the cuttings into the central channel.
The reverse circulation bit is the pivotal factor in the formation of reverse circulation. To improve the reverse circulation effect, this paper proposes that a secondary injector device be set at the central hole of the original reverse circulation bit. The injector device used for the hollow-through DTH reverse circulation bit is a gas injector designed with the gas injecting principle. Based on the structure principle of the injector and the actual structure of the DTH reverse circulation bit, it is used the bottom nozzle of the bit as injector nozzle and add a pressure diffusion slot, so a multi-nozzle injector structure at the bottom of the bit is formed.
The secondary injector device can effectively improve the reverse circulation effect of the hollow-through down the hole (DTH) hammer drilling technology. The influence of the four structural parameters, namely, secondary injector hole diameter d, center hole diameter D, injector hole angle ?, and distance h from the injector hole to the reverse circulation drill bit bottom, on the injector coefficient n was studied by computational fluid dynamics (CFD) simulation to determine the structure size. The CFD results were verified by experimental method. The results showed that the reverse circulation effect changed with the changes in the secondary injector device structure parameters d, D, ?, and h. A combination of structure parameters allowed the drill bit to achieve the best reverse circulation effect. Considering the effects of the four parameters, d=11 mm, D=44 mm, ?=30°, and h=180 mm were the more rational parameters. Moreover, laboratory experiments were conducted to verify the CFD simulation results. The simulation results that showed the variation of
The hollow-through DTH hammer-based reverse circulation continuous coring drilling technology is featured by reverse circulation of fluid medium through the entire hole and continuous upward conveyance of the cores during drilling. This paper studies the structural parameters of the secondary injector device of the reverse circulation drilling bit in order to improve the rate of core recovery.
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.
Increasing global demand for additional energy requirement - forecasted to increase up to 74% by 2030 - has catalyzed the petroleum industry to perform extensive research into rectifying structural well integrity issues in order to extend the life and return older wells to production and injection. These issues are mainly caused by failure of corroded surface casing. Due to the inability to provide integral barriers in the 95/8? casing x 12¼? hole annulus, these wells are planned to be abandoned or completed as single zone wells. Perforate, Wash and Cement remediation strategy is one of the innovative approaches that can be utilized in wells to provide strong integral cement barriers behind the 95/8? casing to prevent reservoir fluids migrating to surface. This approach is gaining increased popularity due to a number of economic and environmental advantages such as reduction in costs for abandonment of current wells and drilling of new wells, mitigate environmental concerns, restoring the well production/injection with minimum workover costs and eliminating the risk with section milling of not being able to re-enter the casing.
The research utilizes a Novel Remediation technique for providing integral cement barriers in the 95/8? x 133/8? casing annulus above the reservoir for wells experiencing migration of hydrocarbons from reservoir through the 95/8? x 133/8? casing annulus. The planned methodology starts with completion recovery followed by running cement, noise, temperature and corrosion logs in order to evaluate the cement quality behind 95/8? casing above the reservoir and the corrosion level for 133/8? casing.
Findings from the noise/temperature logs and oil sample evaluation indicate that oil is migrating from the reservoir, through 95/8? x 133/8? casing annulus, dripping at surface through the 30? conductor pipe. The cement bond logs indicate poor cement behind 95/8? casing above the reservoir. However, the results from Metal thickness detection logs indicate low corrosion (~10-15%) in the 133/8? casing, eliminating the necessity for any external casing patch to restore 133/8? structural integrity. Therefore, Perforate, Wash and Cement remediation strategy was successfully applied and the integrity of the dual water injector well was restored by placing 100-feet cement barrier behind perforations in the 95/8? casing above the reservoir. In addition a 7? short tie-back was installed over the perforated cemented interval. Hence, the 95/8? casing was re-established as a well barrier element in the well, allowing the injection rate for the well to be restored.
This strategy may be developed as an economic saving technology as it saves us approximately 5-8 days per well with associated significant CAPEX and OPEX savings by avoiding additional costs on section milling and solving problems encountered with section milling. It is feasible to be applied in offshore wells having integrity issues as it extends the life of the well without taking on additional environmental risk.
Zhou, H. (SINOPEC Research Institute of Petroleum Engineering) | Niu, X. (SINOPEC Research Institute of Petroleum Engineering) | Fan, H. (SINOPEC Research Institute of Petroleum Engineering) | Wang, G. (SINOPEC Research Institute of Petroleum Engineering)
Drilling wells for oil/gas has been increasingly challenging with the companies moving towards difficult environments, such as in Tarim basin of China, some reservoirs buried so deeply (>7,000m) that we experience high temperature and pressure. The problems faced in these locations range from very narrow margin between pore (or collapse) and fracture pressure. The density of drilling fluid is often affected by HTHP, the careful research on the drilling fluids density at HTHP is very important for precisely predicting ESD as well as controlling the downhole pressure. A utility calculation model of drilling fluids density and ESD was proposed, which can predict the HTHP density and ESD.
Firstly, a new utility artificial neural network HTHP drilling fluid density prediction model was established based on the traditional BP neural network and PSO (Particle Swarm Optimization) optimization method. Then PSO-BP neural network HTHP drilling fluid density prediction model was proposed, in which the influence of drilling fluid component (oil phase, water phase volume fraction) was taken into account. Available experimental measurements of water-based and oil-based drilling fluids at pressure ranging from 0-96MPa and temperatures up to 183°C were used to develop and the PSO-BP network model and then the network weights, threshold parameters. Through this model the high-precision HTHP drilling fluids density can be obtained easily with the knowledge of the drilling fluids component data (oil phase and water phase volume fractions) and its density at standard conditions(0MPa, 20°C) based on the basic principle of PSO-BP network. Moreover, an new comprehensive ESD calculation model of HTHP well was established, which is applicable for all common type drilling fluids and through we can obtained the ESD profile of the well easily.
The prediction of this model has been compared with an extensive set of data from literature, the comparisons of different fluids density in HTHP show very good agreement, the prediction accuracy was improved, and in which the maximum average absolute error of predictions is less than 0.005sg. Finally, the proposed model has been applied for HTHP drilling fluids density and ESD prediction in several wells of the Tarim basin in China, the results show that the proposed model can exactly provide the HTHP drilling fluids density and ESD profile.
This study proposed an utility calculation of HTHP drilling fluids density and ESD profile while drilling, based on the new PSO-BP neural network, the optimal network weights, threshold parameters of was obtained, through which the high-precision drilling fluids density and ESD can be obtained easily. Moreover, the model has been verified and applied for field monitoring. Therefore, this model can be applied to provide more accurate predictions of HTHP drilling fluids density and ESD while drilling.
The torque and drag problem is one of the major drilling challenges in deviated, horizontal, extended reach and multilateral wells and thus needs industry attention. In case of HTHP drilling, the excessive torque and drag can lead to various drilling problems including downhole tool failure. This problem is further aggravated in the presence of water-based muds due to usually high Coeffiecnt of Friction (COF) values of WBMs compared to OBMs. The COF of WBMs often lead to the termination of drilling operation before the target point, especially in extended reach drilling operations. That is why various types of solids and liquid lubricants are incorporated into a water-based mud to overcome the torque and drag problems. Most of the conventional lubricants are, however, not environment friendly and thus not appropriate in sensitive environments. This paper describes the application of an ecofriendly lubricant that can reduce the COF values of water-based mud significantly. It has been developed using a waste by-product of the food industry without including any additives to maintain the environment friendliness of the finished product. To evaluate the performance of the new lubricant, lubricity tests were conducted on three different water-based muds by incorporating 2-4% by volume of the new lubricant.
Experimental results indicate a significant reduction of the COF values of water-based muds in the presence of the new lubricant. Comparison of the COF reduction capability of the new lubricant with diesel and mineral oil lubricants indicates that the new lubricant has similar or better performance with respect to these lubricants. As the lubricant has been developed using a locally available food industry waste product, additional benfits may be realized in the potential growth of local industries. Due to the eco-friendly nature of the lubricant it will have no detrimental impact to the surrounding environments, ecosystems, localities and habitats.
Deepwater oil and gas exploration continues to push the technological and regulatory boundaries of drilling techniques and drilling equipment, as exploration moves ever deeper and into more remote locations. These challenges call for new and enhanced development of drilling techniques and drilling equipment. This is clearly evident after the Macondo incident, where specific new regulatory requirements have been implemented, especially for well control.
To meet these challenges, a new drillship design has been developed that is capable of applying a suite of drilling techniques to various well conditions while providing improved safety by including systems such as riser gas handling and downhole event detection systems. The systems and capabilities of the new drillship design make it a versatile asset that is able to drill in difficult conditions with the ability to prevent, manage and react to emergency situations. Systems included with the new drillship design are the following: Managed Pressure Drilling (MPD); Underbalanced Drilling (UBD); Riser Gas Handling (RGH); Down Hole Event Detection Systems; Integral Full Well Testing.
Managed Pressure Drilling (MPD);
Underbalanced Drilling (UBD);
Riser Gas Handling (RGH);
Down Hole Event Detection Systems;
Integral Full Well Testing.
This paper describes how a new innovative drillship design enhances the drilling efficiency and capabilities, as well as the safety aspects of deepwater drilling operations. Advanced Managed Pressure Drilling (MPD), Underbalanced Drilling (UBD), Well Testing, Riser Gas Handling (RGH) and down hole event detection systems are built into the design of the drillship. The additional deck space, large oil storage capacity, dual moon pools and large Variable Deck Load (VDL) of the drillship design adds capabilities and functionalities supporting more efficient and safer drilling operations. In case of an emergency well situation the drillship can also act as a single well response vessel.
Olutimehin, K. (Schlumberger) | Taoutaou, S. (Schlumberger) | Pasteris, M. (Schlumberger) | Wuttikamonchai, P. (Schlumberger) | Vargas Bermea, J. A. (Schlumberger) | Ashraf, S. (Schlumberger) | Kaotun, K. K (PTTEP) | Phonpuntin, V. (PTTEP)
The optimization of spacer fluid properties is very critical for achieving good mud removal in primary cementing. A new, laminar spacer fluid formulation using surfactant/solvents based on engineeredchemistry approach and incorporating high-temperature mud removal (HTMR) fibers was introduced to improve cementing placement results for a major operator in the Gulf of Thailand. The successful implementation of this technology has been accomplished in the field through the application of the Design-Execution-Evaluation workflow best practices. The team carried out extensive laboratory testing to validate placement efficiency at conditions representative of high-temperature production tubing jobs. A detailed analysis was carried out to compare performance (with fibers) with the legacy system (without fibers) from the same field. The testing results showed significant improvement in the stability of the new system at high temperature and a much higher cleaning efficiency attained using a proprietary test method. Repeat tests were conducted in different laboratories to ensure reliability and robustness against minor changes in downhole temperature. In order to achieve complete tubing annulus integrity the design workflow required mandatory mitigations for 4 main phenomena (i.e.
Al-Khaldy, M. D. (Kuwait Oil Company) | AlRashidi, A. (Kuwait Oil Company) | Failakawi, K. Al (Kuwait Oil Company) | Dutta, A. (Kuwait Oil Company) | Ayyad, H. (Schlumberger) | Mansour, O. (Schlumberger) | AlMahdy, M. (Schlumberger) | Jamal, S. (Schlumberger)
In North Kuwait, formation evaluation in horizontal/highly deviated wells typically requires the use of Logging While Drilling (LWD) technology. In this paper, we will discuss how for the first time in Kuwait a state-of-the-art wireline open hole tractor has been successfully used to convey an advanced wireline pressure measurement in a horizontal well. Two wells will be discussed in this paper, the first was a short radius horizontal side track in the tight carbonate formation while the second is highly deviated well across sand/shale layers.
Traditionally in horizontal wells, the pressure measurement is either run on drill pipe or LWD. Moreover, the formation tightness posed another challenge, as stabilized formation pressures can be difficult to achieve. To address the challenge of formation tightness and save rig time, a fast wireline pretest measurement tool allowing dynamic control of the pretest system would be conveyed on wireline using Open Hole tractor. A job simulation was conducted, based on the friction force and tool weight, to ensure the ability of conveying the tractor to the required depth in addition to the ultimate tractor drives number with tandem
Both jobs were successfully executed as per plan. The tool was conveyed smoothly across the tight carbonate reservoir to the target depth of 10,030 ft MD at an average tractoring speed of 1800 ft/hr. The job was concluded with a cumulative tractoring footage of 3200 ft and an operating time of 12.5 hours, which resulted in more than 30 hours of rig time savings compared to other alternatives. The requested pressure program was achieved. Due to the pressure tool's low rate pretest capability, in addition to the flexible volume and pretest time options; stabilized formation pressure data could be acquired
The combination of the advanced pressure measurement with a state-of-the-art open hole tractor
As hydrocarbon reserves become scarcer, exploration and development efforts are increasing in locations where the downhole environment is hostile. This paper introduces a new measurement and logging while drilling (MLWD) system capable of operating at up to 200°C (392°F).
In some areas of the world, operators are developing fields in which the great depth of the reservoir results in extremely high pressure. In other areas, the primary concern is the extremely high reservoir temperature. Such environments present challenges when running tools containing any type of electronics. These electronics must be protected from pressure and be either protected from heat or designed to tolerate high temperatures.
High-temperature (HT) wireline logging tools have existed for many years. These tools mostly use flasking technology to insulate the electronics from high reservoir temperatures. The short duration of most wireline runs makes flasking a practical solution, but MLWD tools operate in the well for too long for this technology to remain effective. Instead, the electronics must be designed to operate at high temperatures without insulation. This requirement has previously limited the range of temperatures in which operators use measurement-while-drilling (MWD) and logging-while-drilling (LWD) tools. The new system contains electronics designed to operate at up to 200°C. It has undergone extensive field testing and has demonstrated its reliability over long periods of sustained high temperatures. The system comprises a base-services collar, providing real-time measurements of well trajectory, borehole pressure, drillstring dynamics, and natural formation gamma ray emissions. It also includes a set of additional collars, providing resistivity, density, and neutron-porosity measurements in zones where these have traditionally been unavailable.
The new system has been used in multiple regions in multiple HT wells, delivering significant time and cost savings to operators. It has allowed the wells to be drilled more quickly as a result of the reduced need for temperature mitigation and has further reduced costs by eliminating or reducing the need for dedicated wireline logging runs.