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To accelerate learning, an operator deployed a real-time, closed-loop downhole automation system (DHAS) in conjunction with wired drillpipe in the 8¾-in.-hole Field trials were conducted by BP on the commercial version of wired pipe with a comprehensive suite of logging-while-drilling (LWD) tools, measurement-while-drilling (MWD) functionality, and rotary-steerable- capability on two Wyoming wells in 2007.
Reservoirs consisting of heterogeneous carbonates and shaly sands pose formation evaluation challenges for conventional logging-while-drilling (LWD) measurements. Magnetic resonance techniques hold promise for improving understanding of these reservoirs. Core-flow tests are usually conducted to test and model stimulation treatments at laboratory scale, to predict the performance of such treatments in carbonate reservoirs.
A new multilayer boundary‑detection service has been introduced to resolve the geological uncertainty associated with horizontal wells in Bohai Bay. Geosteering and real time reservoir characterization were used to reduce the uncertainty. Reservoirs consisting of heterogeneous carbonates and shaly sands pose formation evaluation challenges for conventional logging-while-drilling (LWD) measurements. Magnetic resonance techniques hold promise for improving understanding of these reservoirs.
Results to date are compared with previous performance in the Gulf of Thailand (GoT). Reservoirs consisting of heterogeneous carbonates and shaly sands pose formation evaluation challenges for conventional logging-while-drilling (LWD) measurements. Magnetic resonance techniques hold promise for improving understanding of these reservoirs. This paper discusses ultradeep directional-resistivity (DDR) logging-while-drilling (LWD) measurements for high-angle and horizontal wells that have been applied recently with success on the Norwegian continental shelf (NCS). Determining the fluid properties of a reservoir by using pressure/volume/temperature (PVT) analysis is essential to petroleum reservoir studies, production equipment design, and reservoir recovery efficiency estimation.
Data-driven, or top-down, modeling uses machine learning and data mining to develop reservoir models based on measurements, rather than solutions of governing equations. Seminole Services’ Powerscrew Liner System is a new expandable-liner hanger that is set with torsional energy from the topdrive. Stuck pipe has traditionally been a challenge for the oil and gas industry; in recent years, operators have become even more determined to reduce the effect of stuck-pipe issues. The primary purpose of this study is to develop a method that overcomes the restrictions of rock-mechanics tests with respect to unconventional shale formations. The Earth is complex in all directions, and hydrocarbon traps require closure—whether structural or stratigraphic or both—in three dimensions.
Uncontrollable kicks are the most costly events that occur while drilling for oil and gas. Formation water flow sometimes turns to kicks that lead to life threatening and environmentaly disastrous blowouts. Prediction of the possible abrupt pressure surges that characterize the subsurface geological setting before drilling sheds light on some of the challenges that may be encountered along the bore-hole trajectory. This will also help curtail human error during penetration of certain zones along the well-hole trajectory, and consequently reach the objective depth safely and with less nonproductive time (NPT).
Before drilling, pore andfracture pressure predictions from seismic velocity are critical for assessing the economic feasibility and safety for the whole prospective trap. Integrating the seismic velocity drifts and the sequence stratigraphy semblance at the proposed location can point to the possible pressure transgressive intervals that can cause a sudden pressure surge (PS). Moreover, modifying the drilling tolerance window (DTW) to accommodate the expected hydrocarbon column in the prospective reservoirs reduces the potential of unexpected hard kicks at the shale – sand interface.
This paper briefly discusses the impact of subsurface geopressure compartmentalization on seismic velocity drift and consequently on PS. It also examines the subsurface geological setting that can cause substantial pressure increase penetrating the lithological interfaces. Therefore, the pressure transgression and expected excess pressure in pay zones should be encompassed within the numerical algorithm of the predictive model before drilling. Monitoring the logging while drilling (LWD) data slopes in shale beds can successfully point to a possible kick ahead of the drill bit. Maneuvering the mud weight and casing program while drilling within the DTW based on the modified numerical pressure profile can achieve safe drilling.
Examples from onshore and deep-water wells are shown. This paper covers several geological features that correlate to open bore-hole flows or kicks that sometimes develop to a blowout if the formation flow is not controlled by the right mud weight kill. Detecting these subsurface features and their associated seismic velocities before drilling can lead to safe drilling and avoiding NPT. Moreover, this paper sheds light on the potential to enhance drilling safety in advance, even in cases where managed pressure drilling (MPD) equipment is used.
The largest risks in deepwater well construction often occur in the shallow, surface hole sections where seismic uncertainty is high. This seismic uncertainty translates into increased error when estimating the position and extent of shallow hazards such as gas charged sediments, high pressure zones, wellbore stability concerns, faults, etc. Should these hazards be encountered unexpectedly, or without adequate preparation, then the associated operational costs and risks to safety can be extremely high. It is therefore critical that these risks are managed appropriately to ensure drilling success. Minimizing the uncertainty in the surface seismic requires adequate knowledge of both the compressional and shear velocities of these shallow sediments. Being able to turn this information into real-time drilling solutions to mitigate risk requires the acquisition of these measurements using logging while drilling (LWD) sonic tools in a wide variety formation types, often in large, and potentially washed out, surface holes and in a wide variety of mud types. This paper will discuss the physics of acquiring quadrupole shear measurements in large boreholes and slow formations. The limits of measurement will be explored, using both modeled data and real well examples, in a variety of formations, with different mud types, and in different borehole sizes. The effect on measurement quality as a result of the interplay among these three key parameters is revealed. The results show that, although the acquisition of reliable shear data in these conditions is challenging, it is not impossible, provided that the LWD tool is correctly designed, the physics are understood, and suitable processing applied. The latest generation of LWD sonic tools can therefore offer unique solutions to managing drilling risk.
As LWD sonic tools have become more advanced, they have become more routine in use and are now commonly used in multiple hole sections from surface to total depth. Utilizing the compressional and shear measurements from these tools as inputs into analysis to address concerns such as wellbore stability or seismic remigration requires a thorough understanding of the physics of the measurement, the effects of the borehole conditions and the limits of their capability. The challenges inherent in acquiring compressional velocity in large holes and slow formations are well documented, but the effect of these formations on measurements of LWD quadrupole shear has been much less discussed. The newly conducted intensive modeling study and field data analysis of the LWD quadrupole modes reveal that the effect of the drilling mud properties (slowness and density) is also important as well as the formation properties and the borehole size for deriving robust shear slowness.
Maus, Stefan (H&P Technologies) | Gee, Timothy (H&P Technologies) | Mitkus, Alexander M. (H&P Technologies) | McCarthy, Kenneth (H&P Technologies) | Charney, Eric (H&P Technologies) | Ferro, Aida (H&P Technologies) | Liu, Qianlong (H&P Technologies) | Lightfoot, Jackson (H&P Technologies) | Reynerson, Paul (H&P Technologies) | Velozzi, David M. (H&P Technologies) | Mottahedeh, Rocky (United Oil & Gas Consulting Ltd)
Development of autonomous drilling technologies requires the automated analysis and interpretation of Logging While Drilling (LWD) data to optimally land the well in the target formation and keep it in the pay zone. This paper presents a fully automated geosteering algorithm, which includes advanced LWD filtering, fault detection, correlation, tracking of multiple interpretations with associated probabilities and visualization using novel stratigraphic misfit heatmaps.
Traditional geosteering uses manual stretch, compress and match techniques to correlate measurements along the subject wellbore against corresponding reference type logs. This results in a crude representation of strata by linear sections with offsets at fault locations. Instead of automating this manual process, we instead determine the possible interpretations as solutions of a geophysical inverse problem in which the total misfit between the subject and reference data is minimized. Interpretations are parameterized as discontinuous splines to accurately follow curved strata interjected by fault offsets. To account for ambiguities, multiple possible interpretations are continuously tracked in real time and assigned probabilities based on the misfit between the latest measurements and the reference data. Unrealistic solutions are suppressed by penalizing strong curvature and large fault offsets. Viable interpretations are simultaneously visualized in real time as paths on a novel stratigraphic misfit heat map, where they may be corroborated against valleys of minimal misfit between the subject and reference data. The user can guide the interpretation by setting control points on the heat map which the automated solutions must respect.
The algorithm has been validated using wells from different regions across North America for which previous manual geosteering interpretations are available. The automated spline interpretations represent the actual curved strata more accurately than manual interpretations. Operationally, the automated interpretations can be provided within minutes compared to typical manual turn-around times of hours. Automation leads to more consistent and repeatable results, removing the subjectivity of manual interpretations.
Amorocho, Claudia (Weatherford International) | Galindo, Jhonny (Weatherford International) | Hernandez, Julian (Weatherford International) | Stich, Chad (Weatherford International) | Valecillos, Juan (Weatherford International) | Oliver, John (Merit Energy) | Scherer, Gary (Merit Energy)
This case study shows a cooperative implementation of managed pressure drilling (MPD), logging while drilling (LWD) and rotary steerable system (RSS) technologies to prevent non-productive time (NPT) while drilling through a section with a tight pressure window in a highly over-pressured reservoir in the US. Drilling risks were proactively reduced by providing real time data transmission for reservoir characterization and identification of critical well sections.
The bottom hole assembly (BHA) was designed to be able to provide high quality measurements according with specific priorities in real time formation characterization and post mortem evaluation. The data transmission was also optimized to be able to monitor the performance of the rotary steerable system (RSS) as well as provide logging measurements that allowed decision making in real time. The implementation of MPD and the continuous monitoring of pressure while drilling (PWD) data allowed to adjust the downhole pressure profile to minimize the impact of drilling hazards by early detecting micro influxes and micro losses reducing considerably their size and impact to control them.
Acquisition and transmission of high-quality logging while drilling data in real time allowed to identify the formations being drilled using Gamma Ray and resistivity logs anticipating the risk associated with each formation. The accurate identification of the pore pressure ramp, a consequence of using real-time MWD GR logging to correlate incoming formation tops with offset data, and the monitoring of the PWD data help to proactively respond to the imminent drilling hazards allowed to drill through these problematic sections using an underbalanced mud weight with the help of MPD which can adjust the pressure profile immediately reducing the risk of NPT. In addition to LWD and MPD technologies, the implementation and monitoring of RSS reduced the risk of downhole mechanical problems. Furthermore, acquired high-resolution sonic and density data from memory provided means to tie together the seismic data, in time, and LWD data, in depth, in order to make accurate predictions of incoming formations tops for future wells. This improved predictive capability to identify the depth range of the pore pressure ramp, while the correlative in-formation log signatures provided robust analysis of offset producing trends.
Drilling scenarios that otherwise deemed unattainable due to the big potential for drilling hazards, can currently be tackled safely while also optimizing capital expenditure through the implementation and monitoring of reliable LWD, MPD and RSS systems. The designed BHA allowed reliable data acquisition and the use of MPD enabled the versatility of instantaneously adjusting the downhole pressure profile leading to a flawless drilling operation with reduced NPT associated to pressure-related issues.
HFTO is a self-excited torsional vibration of the drillstring caused by the interaction of the drill bit and the rock. The latest downhole measurement devices can measure and record torsional accelerations at frequencies greater than 100 Hz and enable observation of HFTO in the field. Consequently, this phenomenon has been well-described and analyzed. In contrast to stick/slip, which occurs at the first torsional eigenfrequency of the drillstring, HFTO occurs at a higher natural torsional frequency, typically between 50 and 500 Hz. In most cases, the mode exhibiting the highest excitability is the stick/slip mode.