Not enough data to create a plot.
Try a different view from the menu above.
The definition of a tight gas reservoir is that the reservoir does not produce at commercial gas flow rates, or recover commercial volumes of natural gas, unless a hydraulic-fracture treatment is properly designed and pumped. As such, the entire drilling and completion procedures should focus on making sure the optimum fracture treatment can be designed and pumped in the field. When drilling a tight gas well, the most important aspect of the drilling operation is to drill a gauge hole. Many times this means the well should be drilled at a balanced mud weight or slightly overbalanced. In other cases, air drilling or underbalanced drilling works best, as long as the hole remains in gauge.
Loss of circulation is the uncontrolled flow of whole mud into a formation, sometimes referred to as a "thief zone." This article discusses causes, prevention, and remedial measures for lost circulation. Figure 1 shows partial and total lost-circulation zones. In partial lost circulation, mud continues to flow to surface with some loss to the formation. Total lost circulation, however, occurs when all the mud flows into a formation with no return to surface.
As production declines over time, the injection of fluids is required to enhance oil recovery and/or maintain the reservoir pressure. Whether applied at field startup or as a secondary recovery technique, waterflooding can boost oil recovery from less than 30% to 30–50%. The common problems associated with waterflooding include loss of injectivity, premature injector failure, and injection conformance. This can also lead to issues around insufficient voidage replacement, which can result in lower reservoir pressure and the production of fluid with a higher gas/oil ratio. In total field recovery, this ultimately means lower production and oil left untapped in the well.
This paper presents a case study of fracture interaction mitigation in a multistage horizontal stimulation of an offshore Black Sea well. The authors discuss a multifaceted approach in applying lessons learned and pre-job geomechanical analysis of depletion-induced stress differential and its effects on fracture interactions. Intrastage fracture interference presents unique challenges that typically are managed on a case-by-case basis. This study aims to present critical analyses that are paramount to planning stimulation treatments in highly depleted segments and reservoirs with close-proximity wells. The operating company began a field redevelopment project in 2013 for a field in the Black Sea that was already producing from horizontal wells with multistaged fractured wells.
Abstract Unconventional and tight gas reservoirs are located in deep and competent formations, which requires massive fracturing activities to extract hydrocarbons. Some of the persisting challenges faced by operators are either canceled or non-productive fractures. Both challenges force oil companies to drill new substitutional wells, which will increase the development cost of such reservoirs. A novel fracturing method was developed based on thermochemical pressure pulse. Reactive material of exothermic components are used to generate in-situ pressure pulse, which is sufficient to create fractures. The reaction can vary from low pressure pulse, to a very high loading up to 20,000 psi, with short pressurization time. In this study, Finite Element Modeling (FEM) was used to investigate the impact of the generated pressure-pulse load, by chemical reaction, on the number of induced fractures and fracture length. Actual tests of pulsed fracturing conducted in lab scale using several block samples compared with modeling work. There was a great relationship between the pressure load and fracturing behavior. The greater the pulse load and pressurization rate, the greater the number of created fractures, and the longer the induced fractures. The developed novel fracturing method will increase stimulated reservoir volume of unconventional gas without introducing a lot of water to formation. Moreover, the new method can reduce formation breakdown pressure by around 70%, which will minimize number of canceled fracturing.
Abstract During drilling of permeable reservoirs, drilling fluid may penetrate the formation and induce damage to the reservoir rock. Specifically, solids present in the drilling fluid may enter the formation and cause subsequent reduction in reservoir permeability in the area near the wellbore. When drilling with a water-based drilling fluid in a reservoir, various polymer-based additives are normally applied to reduce the filtration loss. These additives, such as Xanthan Gum, Poly Anionic Cellulose (PAC) and Starch may help in reducing losses to the formation in presence of small pore-throats and low differential pressures. If the pore throats exceed e.g. 20μm and differential pressures reach 500psi, these additives have little effect on reducing loss of drilling fluid to the formation and thereby little effect in preventing solids from entering the formation. Lost circulation is particularly challenging when losses occur in the reservoir section. This is because LCM treatment may create formation damages. Green et al. (SPE-185889) showed the nature of drilling fluid invasion, clean-up, and retention during reservoir formation drilling. They also showed the lack of direct relation between fluid loss and formation damage. In light of such ideas, a development of new Non-Invasive Fluid (NIF) additives was conducted. These additives were able to handle downhole pressure differences and create a preventative sealing of a permeable formation when applied into a solids-free drilling fluid. Ceramic discs of various permeability and mean pore-throat size were installed into a HTHP pressure cell. Drilling fluid was pumped through the cell and a filter cake was formed across the ceramic disc. A pressure of 500psi was applied and filtration loss was measured over a 30-minute period. Examples are herein presented showing how filter cake materials were applied into the drilling fluid and effectively sealing the permeable surface of the ceramic disc. Also, it will be shown how the filter cake was effectively removed from the discs using a breaker solution. Furthermore, a selection of experiments is presented, showing the possibility to heal lost circulation in permeable reservoirs without the presence of weighing materials, clays or drill-solids in the drilling fluid. A test was also conducted in such a way that the disc was fractured inside the test cell to investigate the impact on fluid loss.
Yi, Ming (CNPC Xibu Drilling Engineering Company Ltd) | Liu, Ling (CNPC Xibu Drilling Engineering Company Ltd) | Wei, Qiang (CNPC Xibu Drilling Engineering Company Ltd) | Chen, Liang (CNPC Xibu Drilling Engineering Company Ltd) | Li, Binging (CNPC Xibu Drilling Engineering Company Ltd) | Guo, Zhiqi (CNPC Xibu Drilling Engineering Company Ltd) | Xu, Yangyang (CNPC Xibu Drilling Engineering Company Ltd) | Huang, Xingning (CNPC Xibu Drilling Engineering Company Ltd)
Abstract Exploration focus is moving into deeper targets of high pressure and high temperature (HPHT) regime due to the ever-increasing energy demand of China. Overpressure and wellbore instability related problems in such setting are mainly associated with narrow drilling margin resulting in severe well control incidents and increased drilling cost. In order to reduce drilling risks and operation costs, an accurate geomechanical model is necessary. The model provides technical support for drilling process and minimum reservoir damage due to optimal mud weight program. Well-scale (1D) Mechanical Earth Model (MEM) is constructed on the offset wells which consist of rock strength properties and stress profile by incorporating all available data including open hole log data, geomechanical core lab results, LOT/FIT, direct pore pressure measurements and drilling events. Furthermore, 3D geomechanics model is generated using available well-scale MEM data in the field and distributed throughout the field which guided by seismic interpretation data as distribution control. The 3D geomechanical model is used to design mud weight and casing program for the upcoming well. The offset wells in the study areas were drilled through complex geological settings with high overpressure (13500 psi) and high temperature (200-220 deg C). Therefore, drilling operations is also risky with different types of drilling events encountered frequently including stuck pipe, inflow, losses and connection gas etc. With 3D geomechanical model as the foundation, the integrated approach helps ultra-deep wells to reduce serious wellbore instability caused by abnormal formation pressure, wellbore collapse and other complex drilling problems. The implementation of systematic and holistic workflow has proven to be extremely successful in supporting the drilling of HPHT wells in China. The integrated solution has been applied in the ultra-deep well, recorded an improvement in ROP by 35.3% and decrease no-productive time (NPT) by 25.3% compared with offset well. The geomechanical approach provides a convenient means to assist field engineers in the optimization of mud weight, risk assessment, and evaluation of HPHT wells drilling performance. The findings will provide reference and guideline for de-risk and performance improvement in HPHT wells drilling.
Al-Nakhli, Ayman R. (Saudi Aramco) | Tariq, Zeeshan (King Fahd University of Petroleum and Minerals) | Mahmoud, Mohamed (King Fahd University of Petroleum and Minerals) | Abdulraheem, Abdulazeez (King Fahd University of Petroleum and Minerals)
Abstract Commercial volumes of hydrocarbon production from tight unconventional reservoirs need massive hydraulic fracturing operations. Tight unconventional formations are typically located inside deep and over-pressured formations where the rock fracture pressure with slickwater becomes so high because of huge in situ stresses. Therefore, several lost potentials and failures were recorded because of high pumping pressure requirements and reservoir tightness. In this study, thermochemical fluids are introduced as a replacement for slickwater. These thermochemical fluids are capable of reducing the rock fracture pressure by generating micro-cracks and tiny fractures along with the main hydraulic fractures. Thermochemical upon reaction can generate heat and pressure simultaneously. In this study, several hydraulic fracturing experiments in the laboratory on different synthetic cement samples blocks were carried out. Cement blocks were made up of several combinations of cement and sand ratios to simulate real rock scenarios. Results showed that fracturing with thermochemical fluids can reduce the breakdown pressure of the cement blocks by 30%, while applied pressure was reduced up to 88%, when using thermochemical fluid, compared to slickwater. In basins with excessive tectonic stresses, the current invention can become an enabler to fracture and stimulate well stages which otherwise left untreated. A new methodology is developed to lower the breakdown pressure of such reservoirs, and enable fracturing. Keywords: Unconventional formation; breakdown pressure; thermochemicals; micro fractures.
Abstract A new, through-the-bit, ultra-slim wireline borehole-imaging tool for use in oil-based mud provides photorealistic images. The imager is designed to be conveyed through drill-pipe. At the desired well section, it exits the drill pipe through a portal drill bit and starts the logging. Field test measurements in several horizontal, unconventional wells in North America show images of fine detail with a large amount of geological information and high value for well development. A relatively new solution for conveying tools to the deepest point of a high angle or horizontal wells uses a drill bit with a portal hole at the bit face. As soon as the bit reaches the total depth, a string of logging tools is pumped down through the drill pipe. The tools exit the bit through the portal hole, arriving in the open hole and are ready for the up log. The tools operate on battery and store the log data in memory so that no cable is interfering as the drill pipe is tripped out of the well while the tools are acquiring data. The quality of wireline electrical borehole images in wells drilled with oil-based mud has significantly improved in recent years. Modern microresistivity imagers operate in the megahertz-frequency range, radiating the electromagnetic signal through the non-conductive mud column. A composite processing scheme produces high-resolution impedivity images. The new, ultra-slim borehole-imager tool uses these measurement principles and processing methods. Innovating beyond the existing tool designs the tool is now re-engineered to dimensions sufficiently slim to fit through drill pipes and to use through-the-bit logging techniques. The new, ultra-slim tool geometry proves highly reliable and, due to the deployment technique, highly effective in challenging hole conditions. The tool did not suffer any damage and showed only minute wear over more than twenty field test wells. The tool’s twelve-pad geometry provides 75% coverage in a six-inch diameter borehole and its image quality compares very well with existing larger tools. The field test of this borehole imaging tool covers all scenarios from vertical to deviated and to long-reach, horizontal wells. Geological structures, sedimentary heterogeneities, faults and fractures are imaged with detail matching benchmark wireline images. The interpretation answers allow operators of unconventional reservoirs to employ intelligent stimulation strategies based on geological reality and effective well development. A new high-frequency borehole imager for wells drilled with oil-based mud is introduced. Deployed through the drill pipe and its portal bit, the imager carries photorealistic microresistivity images into wells where conventional wireline conveyance techniques reach their limits in both practicality and viability.
Serry, Amr M. (ADNOC Offshore) | Al-Hassani, Sultan D. (ADNOC Offshore) | Ahmed, Shafiq N. (ADNOC Offshore) | Khan, Owais A. (ADNOC Offshore) | Aboujmeih, Hassan F. (ADNOC Offshore) | Zakaria, Hasan (ADNOC Offshore) | Pippi, Olivier P. (ADNOC Offshore) | Salim, Israa A. (Schlumberger) | Abdel-Halim, Amro (Schlumberger) | Donald, Adam (Schlumberger)
Abstract Faulting is one type of structural trap for hydrocarbon reservoirs. With more and more fields moving toward the brownfield or mature operations stage of life, the opportunity to target bypassed or attic oil in the vicinity of bounding fault(s) is becoming more and more attractive to operators. However, without an effective logging-while-drilling (LWD) tool to locate and map a fault parallel to the well trajectory, it has been challenging and potentially high risk to optimally place a well to drain oil reserves near the fault. Operators often plan these horizontal wells at a significant distance away from the mapped fault position to avoid impacts to the well construction and production of the well. Often, the interpreted fault position, based on seismic data, can have significant lateral uncertainty, and uncertainties attached to standard well survey measurements make it challenging to place the well near the fault. This often results in the wells being placed much farther from the fault than expected, which is not optimal for maximizing recovery. In other cases, due to uncertainty in the location of the fault, the wells would accidentally penetrate the side faults and cause drilling and other issues. Conventional remote boundary detection LWD tools do not assist with locating the fault position, as they only detect formation boundaries above or below the trajectory and not to the side. In this paper, the authors propose a novel approach for mapping features like a fault parallel to the well trajectory, which was previously impossible to map accurately. This new approach utilizes a new class of deep directional resistivity measurements acquired by a reservoir mapping-while-drilling tool. The deep directional resistivity measurements are input to a newly devised inversion algorithm, resulting in high-resolution reservoir mapping on the transverse plane, which is perpendicular to the well path. These new measurements have a strong sensitivity to resistivity in contrast to the sides of the wellbore, making them suitable for side fault detection. The new inversion in the transverse plane is not limited to detecting a side fault; it can also map any feature on the transverse plane to the well path, which further broadens the application of this technology. Using the deep directional resistivity data acquired from a horizontal ultra-ERD well recently drilled in the Wandoo Field offshore Western Australia, the authors tested this approach against the well results and existing control wells. Excellent mapping of the main side fault up to 30 m to the side of the well was achieved with the new approach. Furthermore, the inversion reveals other interesting features like lateral formation thickness variations and the casing of a nearby well. In addition, the methodology of utilizing this new approach for guiding geosteering parallel to side fault in real time is elaborated, and the future applications are discussed.