Zhang, X. M. (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum) | Jiang, G. C. (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum) | Xuan, Y. (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum) | Wang, L. (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum) | Huang, X. B. (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum)
Shale gas buried deep in Weiyuan region in China's Sichuan province, the clay-free and water-base drilling fluid should have high density and high temperature resistant. Most viscosifiers such as XG (xanthan gum) could not meet the fluid requires, so a kind of well water-soluble hydrophobic polymer (SSZN) was synthesized and the clay-free drilling fluid meeting the requirements was laboratory formed.
Using acrylamide, AMPS (2-Acrylamido-2-Methyl Propane Sulfonic Acid), hydrophobic monomer and other acrylamide derivatives as monomers, the viscoelastic polymer was synthesized by the micellar polymerization. To get the optimal reaction conditions, the monomer ratio, initiator amount and reaction temperature were selected. With the electrostatic attraction between positive and negative charges and hydrophobic association between hydrophobic groups, the polymer had great viscoelasticity. With the polymer (SSZN) and other drilling fluid additives, a water-based and clay-free drilling fluid system with high density and high temperature resistant was formed.
First, the structure of the polymer was testified by FT-IR and 1H NMR spectrum. The reticular structure was seen by the TEM (transmission electron microscopy). Then, the viscosity of the polymer was tested by ZNN-D6 Viscometer. The polymer aqueous solution with the concentration of 1.5wt% had high viscosity and great temperature resistance. The apparent viscosity was beyond the range and the apparent viscosity was 0.07 Pa s after hot-rolling for 16 h at 130 °C. The viscoelasticity of the polymer was tested by the HAAKE Rheometer. At last, the water-based and clay-free drilling fluid with the density of 2.36 g/cm3 was formed, and after rolling for 16 hours at 150 °C the fluid had well rheological property.
The viscosifier (SSZN) had great viscoelasticity and high temperature resistant. With it a water-based and clay-free drilling fluid with high density and high temperature resistant was formed, which could meet the shale mining requirements in Sichuan Weiyuan region.
An oil and gas operator in Indonesia had a second exploration well (L-2) in the L field located in Seram Island of eastern Indonesia. This field is known for its extremely harsh drilling environment. One of the challenging parts is the overpressured carbonate formation, which was planned to be drilled in the 8½-in section with 17-lbm/galUS water-base mud (WBM) mud density.
Based on the experience in the previous well (L-1) and looking at the challenges that could potentially happen in L-2, good prejob planning is required to improve the drilling performance. A collaborative modeling job was performed—involving well trajectory design, BHA design optimization, hydraulics modeling, and torque and drag modeling—which utilized static simulation as well as drillstring vibrations modeling utilizing finite element analysis (FEA) dynamic simulation. This collaborative modeling greatly improved the bit and bottom hole assembly (BHA) selection capability by eliminating the uncertainty. Additionally, the dynamics simulation was also capable of generating a stable drilling parameters roadmap as a guideline for the driller and directional driller onsite. Several drill bits and BHA options were modeled and simulated under different drilling conditions to determine the most stable configuration. The result shows that the combination of point-the-bit rotary steerable system (RSS) and a seven-blade, 16-mm-cutter bit is the optimal BHA in the 8½-in section to drill through the hard and overpressured carbonate interval within a certain stable drilling parameters window.
The result was satisfactory where the bit-BHA-parameters combination successfully delivered the service for drilling the 2,780-ft interval in 12 fewer days than the expected drilling time (as per AFE with motor BHA), drilling 18 days faster than the previous 8½-in section in L-1 well, and reduced the number of BHA runs by 50%. Such performance was translated into 18 days spread cost saving (USD 2,673,000) for the operator as compared with the previous well, and 12 days cost saving (USD 1,782,000) as compared with AFE days.
Shuai, Li (PetroChina Research Institute of Petro. E&D-Langfang) | Bo, Cai (PetroChina Research Institute of Petro. E&D-Langfang) | Yunhong, Ding (PetroChina Research Institute of Petro. E&D-Langfang) | Yongjun, Lu (PetroChina Research Institute of Petro. E&D-Langfang) | Chunming, He (PetroChina Research Institute of Petro. E&D-Langfang)
Multi-stage fractured horizontal wells can create fracture networks and increase the contact area between fracture and matrix to enhance well productivity and EOR. It has become a tendency to pump large volumes of fluids and proppants with higher and higher slurry rate during hydraulic stimulation. While field production has presented that not all productivities have positively relation with the increase of stimulation scales. Some small-scale fractured wells even perform better than the massive treatment ones.
To investigate this phenomenon, a new evaluation experiment studied by CT scanning and rock mechanics testified the existence of the fracture surface damage, and some key factors were revealed. Moreover, we established a new mathematical model of fracture surface skin with segment characteristics using fluid coupling method based on the classical model of PKN and KGD. Comparison of the Cinco-Ley model and new model revealed that influence of the fracture surface damage skin on productivity was only 5% using Cinco-Ley model, while the influence was 50% using our new model.
The results indicated that for a specific low permeability reservoir, if high net pressure can't create complex fracture, it would bring formation damage in the near well. We put forward a method for low damage treatment as following: 1)utilize the newly developed fracturing fluids such as slick water, low concentration densifier, linear gel (not cross linked), low molecular weight fluid, etc.; 2)Optimize minimum viscosity of fracturing fluid, then optimizing the corresponding pumping rate; 3)Optimize combination of fluid and proppant type and size according new mathematical model; 4) Try acid-fracturing during pad stages so as to minimize formation damage and fracture damage to obtain an optimized propped profile.
The technology has been put in to filed application in 45 wells, the performance of post-fracturing is very remarkable with the daily oil rate being 14m3/d increased more than 32.2% that of the past well stimulation, and it has a great significance in the near future.
Water-based drilling fluids are the most commonly used of the mud systems. High Temperature and Foam Free Water Based Drilling Fluids has been designed for controlling the rheological and filtration and foam properties of water based drilling mud under down-hole conditions.
This unique drilling fluids system has been developed to improve water based drilling operation's speed and save the drilling cost while reducing their environmental impact for rheology and filtration control at high temperatures. Specially-formulated fluid has good lubricity and low toxicity, and at the same time do not create significant foam and corrosion in during drilling operation. This drilling fluids system's unique chemical structure enables this system to provide multifunctional properties such as surface tension reduction, foam control, and viscosity stabilization, HPHT fluid loss controller.
This new drilling fluids system is formulated by using special HPHT synthetic polymers and specialty additives to reduce HPHT fluid loss of the system and provide maximum shale inhibition in HPHT wells, limitation of foam, and increasing ROP. This system significantly reduced the degradation of polymers and fluid loss additives in WBMs up to 375 °F and increase the rheological and filtration stability to improve the thermal stability in higher temperature environments. Experimental results from the performance of this product have been acceptable in down-hole conditions. This also reduces cost and logistics issue especially in offshore and extend the thermal temperature limitations of standard system components, premium starch derivatives and XC polymers.
In present work, laboratory evaluation of specially-formulated fluids to enhance the properties of the HPHT water based drilling mud was investigated. We put and maintain specialty chemicals in from the beginning operation and we did not experience foaming, ever!
Radhakrishnan, Venkataramanan (Schlumberger OVerseas S.A) | Chuttani, Anil (PTTEP) | Anggrani, Fauzia (Schlumberger Overseas S.A) | Nan, Huang (Schlumberger Overseas S.A) | Onkvisit Poy, Sirikanya (Schlumberger Overseas S.A)
The Sin Pu Horm Field is challenging in terms of formation and well location. Past experiences from offset wells in the field and nearby fields showed that drilling has been challenging due to several issues, including hole instability, severe lost circulation zones in shallow depths, steering difficulties, shock, vibration, bit and BHA damage caused by hard, dense, and abrasive formation in the deeper interval. The best strategy to optimize drilling performance and minimize drilling risk is to drill this interval with minimal steering requirements and move all directional requirements to the deeper interval. With this strategy, the main challenge now is to achieve the directional requirement through the hard, dense, and abrasive sandstones. The service company proposed drilling the section with a new-technology bit that utilizes conical diamond elements (CDEs) on the bit blade with a 7:8-lobe 5.0-stage motor. The objectives were completing the build section through the hard, dense, and compact sandstone and enabling smoother toolface control to complete the directional work. The rock strength of the formation ranges from 18,000 to 36,000 psi.
The PDC bit has CDEs with an ultrathick synthetic diamond layer that gives extra durability for drilling at higher ROP. The bit can withstand more weight on bit compared with conventional PDC bits of the same size, resulting in more mechanical energy to fail the formation more efficiently. The CDEs protect the PDC bit and makes it more stable, resulting in better toolface control.
The 8½-in directional section was successfully built from 10° to 49° with excellent toolface control and an average ROP of 3.5 m/h. The strategically placed CDEs on the bit blades in conjunction with conventional PDC cutters not only increased the point loading but also enabled smoother torque control, leading to smoother toolface control. None of the offset wells achieved the feet of drilling directional profile through this interval. The bit achieved the directional objectives and came out in good dull condition. By putting the directional requirement in the deeper section, the operator finished its well in 80 days, compared with an average of 100 days required by offset wells.
The operator accepted that the bits with CDEs are not only more durable but enable drilling directional profiles better than conventional PDC bits. The operator changed the drilling strategy to put all directional work in the 8½-in section. This strategy will increase drilling efficiency and lower the drilling risk of having directional work in the 12¼-in section that poses a challenge to formation stability. The next well is planned with the same bit with CDEs to minimize the number of runs.
Using the right offset well data to plan the next project is critical, but performance expectations get diluted when metrics are averaged over large depth ranges. Focusing on the rate of penetration (ROP), a benchmarking process was developed to improve drilling efficiencies. The whole process was automated and included a real-time analysis of the well being drilled that was capable of quickly identifying the 1) offset wells based on location, lithology, well type, and performance; 2) sectors within those wells with common formation, wellbore, and tubular characteristics; and 3) the effective technical limit (ETL)—the best drilling performance that realistically can be repeated. The process mentioned in this paper identifies opportunities for operators to reduce inefficiencies while drilling, allowing users to take action while there is still opportunity to mitigate or eliminate the damage.
Using the guided workflow and real-time data to identify and select the appropriate offset wells, multiple ETL sectors are created based on the characteristics they share (formation, wellbore, tubular). During real-time operations, when the same set of characteristics for a particular sector is met, ETL data for that sector are displayed, and users can evaluate performance in real time compared to best historical performance. This paper also presents a case study in which this process was applied to improve an operator's drilling efficiency.
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.
Abdelaziz, Sherif (Halliburton) | Leem, Junghun (Halliburton) | Praptono, Andri Setyanto (Halliburton) | Shankar, Pranay (Cairn India Limited) | Mund, Bineet (Cairn India Limited) | Gupta, Abhishek Kumar (Cairn India Limited) | Goyal, Rajat (Cairn India Limited) | Sidharth, Punj (Cairn India Limited)
A tight-gas reservoir commonly refers to a low-permeability reservoir that mostly produces natural gas. Irrespective of the reservoir rock type (e.g. sandstone, shales, coal seams or volcanics), they all have one thing in common—these reservoirs cannot be produced at economic rates without an effective hydraulic fracturing treatment.
In conventional reservoirs, rock flow capacity is usually sufficient to allow for hydrocarbons flow; therefore, hydraulic fracturing is broadly considered as a remedial technique to improve the productivity of suboptimal producing wells. In this study, fracturing was not originally considered in the primary drilling and completion planning phases, which in many cases limited the effectiveness of fracturing treatments because of challenges resulting from the well architecture, trajectory, azimuthal orientation with respect to dominant stress regimes, and other factors. As the importance of unconventional resources for hydrocarbon production has increased dramatically during the past decade and more attention and efforts are focused globally to explore these reserves, the demand for hydraulic fracturing techniques to prove the economic profitability of these resources has in turn tremendously increased. This has created a paradigm shift, as operators are beginning to recognize that they need to drill and complete wells for hydraulic fracturing to maximize the return on their assets. Therefore, hydraulic fracturing has gained an advanced position in the planning phase of unconventional assets.
Volcanic formations are one of the rarer rock types with the potential for accumulations of hydrocarbons that can produce economically. This rarity has resulted in a lack of understanding across the industry on the nature of these reservoirs and how to successfully turn them into lucrative assets. Because of the tight nature of these formations, optimal hydraulic fracturing strategies are intrinsically necessary for economic production. Without a thorough and integrated understanding of the petrophysical and geomechanical properties of these formations, it will be difficult to interpret the fracture growth behavior and its inherent effect on fracture flow capacity in the production phase.
Pinkstone, H. (Managed Pressure Operations) | Doll, R. (Managed Pressure Operations) | Chandra, M. (Managed Pressure Operations) | Babcock, W. (Murphy Oil Company) | Tilley, V. (Murphy Oil Company) | Choo, B. (Murphy Oil Company)
Previous offset wells drilled in the layered sandstone differentially pressured reservoir formations offshore Malaysia in 1341m water depth, using conventional open system drilling techniques, had experienced lost drilling fluid circulation and hydrocarbon gas kick events, resulting in significant non-productive drilling time, and well control events.
This paper describes how advanced Managed Pressure Drilling (MPD) technology, combined with a drill string conveyed subs based (CCS) continuous circulation system, were deployed on a tender assist semi-submersible rig, and used to effectively and safely drill subsequent development wells. Techniques employed on the project also included Dynamic MPD Well Control and Formation Evaluation procedures, along with dynamic Managed Pressure Cementing (MPC) techniques.
MPD and CCS systems were used, along with MPC, to effectively drill and complete sandstone reservoir layers at various formation pressures depleted from ongoing production, and also over pressured layers charged as a result of water injection activity.
In recent years, the development of shale gas has been paid more attention in China. Since the first shale gas well drilled in 2009, the number of shale gas wells is increasing rapidly. In 2015, the yearly gas production reached 210 BCF. As a matter of fact, China is experiencing an era of shale gas boom regardless of the low oil price in the international market.
From 2010, to speed up the development process, four national shale gas demonstration plots were built, including CW plot, JSB plot, ZT plot, and YA plot. After the JSB plot obtained the first breakthrough in 2013, CW plot took its important step in the development of shale gas resources in 2015. Due to the topographic inequality of Sichuan basin, the multi-well pad was used to solve the problem of well deployment difficulty. In 2013, continuous operation including batch drilling, factory fracturing and gas testing for 13 wells has been successfully conducted in tight-gas reservoir, which provides valuable experience for the shale gas operation model.
This paper aims to describe the continuous operation model and its effectiveness in the pad W202H2 of block Weiyuan (CW plot), located in the southwest China. To improve the cost effective production while maintaining a responsibility for health, safety, and the environment is the most important advantage of the model. To improve the operation effectiveness, two rounds of 3-well zipper fracturing are conducted. The cooperation among water supply, fluid mixing, sand supply, and pumping ensures the continuous fracturing. A total fluid and proppant injection of 189023m3 and 6677m3 for 102 stages/299 clusters are completed in 44 days, which makes the best efficiency record in China. Compared with the single well fracturing, the economic benefit is highly improved and about 6 million dollars are saved. Moreover, the continuous operation model shows a large effective stimulated reservoir volume (ESRV), which is in accordance with the micro-seismic monitoring result.the maximum daily production and wellhead pressure reaches to 32×104m3 and 44MPa, respectively.