Drilling Decisions Research Articles

Multistep-Ahead Prediction of Logging-While-Drilling Resistivity Curves Based on Seismic-Guided Seq2Seq-Long Short-Term Memory

Summary High-temperature and high-pressure reservoirs in complex geological conditions present primary targets and significant challenges in deepsea oil and gas exploration. Limited offshore drilling operations and lack of detailed geological data hinder accurate formation pressure prediction using geoguided and offset imaging, increasing drilling hazards. Logging-while-drilling (LWD) technology provides timely and accurate subsurface information. Resistivity closely correlates with formation pressure and lithology, aiding pressure prediction. Therefore, in this study, we developed an ahead prediction workflow for LWD curves using the resistivity curve (RD) as an example. A seismic-guided sequence-to-sequence framework with the long short-term memory model (Seq2Seq-LSTM) is used to predict the RD curve at a constant depth ahead of the drill bit, utilizing the RD curve of drilled sections and seismic attributes. The network structure incorporates a direct-recursive hybrid multistep prediction strategy based on update threshold control (Dir-Rec-Update), aligning with real-time LWD data acquisition for ahead curve prediction. Using real well data cross-prediction, baseline models such as multilayer perceptron (MLP) and extreme gradient boosting (XGBoost) were compared while also investigating the impact of different configurations on the proposed Seq2Seq-LSTM. The results demonstrate that the method outperforms conventional models, with an average performance across multiple wells under a 5-m update threshold: root mean square error (RMSE) of 0.15, correlation coefficient of 0.88, and coefficient of determination of 0.77. The Seq2Seq-LSTM model and Dir-Rec-Update strategy provide accurate LWD curves ahead of the drill bit, enabling advanced drilling decisions and preventing hazards. Advanced technologies such as empirical wavelet transform (EWT) and feature selection enhance the method’s potential for curve ahead-of-time prediction.

Assisting Directional Drilling by Calculating a Safe Operating Envelope

Summary Nowadays, complex 3D trajectories are executed with a succession of circular arcs (CAs). Although they have constant curvature, their tool face is not constant. Consequently, directional drillers must adjust the tool face regularly to reach the target entry within its tolerances. This paper investigates the use of the constant curvature and constant tool face (CTC in short) curve as an alternative to the CA to assist the directional drilling work to reach the target entry within its boundaries. The problem is addressed by calculating a safe operating envelope (SOE) to reach the boundaries of the target entry and provide a tolerance window for the curvature and tool face to support directional drilling decisions. The target entry tolerance is discretized as a polygon. From the current bit position and its direction, the possible choices of curvatures and tool faces are obtained to reach the edges of the target entry shape. The SOE can be calculated with the CA or with the CTC curve. It is, therefore, possible to compare the advantages and disadvantages of both types of curves to attain the target entry and stay within its boundaries. The CA is shorter than the CTC curve. However, it requires adjusting the tool face during the navigation, which is not the case with the CTC curve. As a result, the directional driller can control the bottomhole assembly (BHA) direction such that the well lands within the target entry limits by using set points for tool face and curvature inside the calculated SOE. Furthermore, a new way to represent the SOE is introduced. It makes use of a 3D cylindrical representation where the curvature is mapped as the height of a cylinder, while the tool face corresponds to the azimuth in the cylindrical coordinate system, and the length is linked to the radial distance. This provides a visual aid to understand the SOE. Moreover, this visualization helps to appreciate the relationship between the initial bit location and direction in the construction of the SOE and how the margins increase in a particular manner as the bit approaches the target entry polygon. The CTC curve is the natural one followed by directional positive displacement motors (PDMs) or rotary steerable systems (RSS). Potentially, the CTC curve may be a more straightforward solution to automated directional drilling control because it is easier to be followed by both PDM and RSS.

Assessing the application of ultradeep azimuthal electromagnetic resistivity tools in detecting igneous formations ahead of the transmitter

The Faroe–Shetland basin (FSB) is considered challenging for oil and gas exploration due to its complex geological structure and limited exploration drilling activity. The costs of drilling in the basin are the most expensive within the United Kingdom Continental Shelf (UKCS) due to varying geological and engineering challenges. The prevalence of igneous sill complexes within the basin present drilling hazards that contribute to drilling nonproductive time (NPT) and are documented in multiple studies. Recent advancements in ultradeep azimuthal resistivity (UDAR) technology which utilizes the look-ahead portion of the electromagnetic (EM) signal presents an opportunity to assess its suitability as a derisking tool to ‘look-ahead’ and detect igneous intrusions in volcanic basins. This paper utilizes resistivity log data from Well 214/28-1, which encountered multiple igneous intrusions and is used to validate the ability of these tools to detect the intrusions. The EM look-ahead technology detected with good confidence the top of an igneous intrusion 72 ft (22 m) true vertical depth (TVD) ahead of the transmitter and once drilled, detect the base of the intrusion 54 ft (16 m) TVD ahead of transmitter. The detection of the intrusions prior to drilling and information on intrusion thickness can enable proactive drilling decisions to reduce nonproductive time.

Study on Rock Mechanics Parameter Prediction Method Based on DTW Similarity and Machine-Learning Algorithms

Rock mechanics parameters are crucial factors for predicting rock behavior in oil and gas reservoirs, optimizing extraction strategies, and ensuring drilling safety. In this study, we propose a random forest (RF)-convolutional neural network (CNN)-long-term short-term memory network (LSTM) fusion model based on the dynamic time warping (DTW) algorithm to construct intelligent prediction models for elastic modulus, Poisson’s ratio, and compressive strength using real-time drilling engineering data. An autoencoder with a sliding window is employed to automatically identify abnormal points or segments in the calculated values of elastic modulus, Poisson’s ratio, and compressive strength obtained from drilled wells. These abnormal values are then corrected using a backpropagation (BP) neural network. Compared to single CNN-LSTM or single RF models, the RF-CNN-LSTM fusion model performs better. It achieves this by effectively combining the strengths of different algorithms in predicting outcomes. The accuracy of the RF-CNN-LSTM fusion model is over 94% when compared to the actual values. Furthermore, the analysis of the relative importance of input parameters reveals that weight on bit (WOB), temperature, displacement, equivalent circulation density (ECD), and mud density are the primary input features for predicting elastic modulus. For predicting Poisson’s ratio, the main input features include WOB, mud density, ECD, temperature, pumping pressure, displacement, and rate of penetration (ROP). Similarly, for predicting compressive strength, the main input features consist of WOB, temperature, displacement, ECD, and mud density. The research findings demonstrate that the rock mechanics parameter prediction models based on the RF-CNN-LSTM algorithm using DTW exhibit high computational accuracy in the B oil field of China. These results are significant for gaining a deeper understanding of the variations in rock mechanics parameters and optimizing drilling decisions.

Azimuthal Prestack Seismic Anisotropic Inversion on a Deep and Tight Carbonate Reservoir From the North Potwar Basin of Pakistan

Summary Quantitative characterization of deep, tight, and heterogeneous reservoirs plays an important role in identifying hydrocarbon pathways for effective and optimal reservoir field development. In this case study, we used an azimuthal prestack seismic anisotropic inversion approach to estimate attributes of horizontal transverse isotropy (HTI) caused by a set of vertical fractures, oriented cracks, and stress. Anisotropic inversion facilitated the conversion of interface properties to the corresponding layer-based properties, which led to the quantitative interpretation of reservoir properties related to azimuthal variation in seismic amplitudes. To estimate the anisotropy magnitude and the direction of the isotropy axis in HTI media, elastic properties (P-impedance and Vp/Vs) obtained from prestack seismic inversion (using six azimuth × four angle stack) served as inputs. The isotropic low-frequency model (LFM) is used as the foundation of the inversion for all azimuths, and the anisotropy effects are later added by updating the model along the azimuths. The direction of the isotropy plane resulting from the anisotropic inversion is determined by using the maximum horizontal stress as a prior constraint, which eliminates any inherent uncertainty. The workflow used effectively characterized the orientation and density of fractures from the recently discovered oilfield reservoirs of the Paleocene (Lockhart) formation located in Pakistan’s north Potwar Basin. It also helped improve the prediction accuracy for fractures in the study area. According to the observations (fractures) from the exploratory drilled well (D1) in the tight carbonate (Lockhart) reservoir, a significant amount of anisotropy magnitude is observed. This provides the basis for hydrocarbon exploration, field development, and reliable drilling decisions.

Reporting the expected exploration outcome: When, why and how the probability of geological success and success-case volumes for the well differ from those for the prospect

Some petroleum explorers and exploration companies do not distinguish the probability of geological success (PoS) and the success-case volumes estimated and reported for the prospect from those for an exploration well. This may mislead decision-makers and investors and may result in disappointments with drilling outcomes. When the well is positioned downdip from the highest closure point(s) of explored segment(s) (also called target(s) or zone(s)) in a prospect in order to penetrate larger than the minimum assumed petroleum column(s), the geological PoS for the well is smaller than the geological PoS for the prospect. Conversely, the expected success-case volumes for such a downdip well are larger than for the prospect. This paper discusses a simple fictitious prospect with three segments and the exploration well that penetrates these segments downdip from highest closure points. The results demonstrate the key differences in geological PoS and success-case volumes between the well and the prospect. Proper reporting of the expected exploration outcomes from planned exploration wells will result in better-informed drilling decisions. Modeling outcomes of drilling the well at various locations within the prospect would help to understand if the well can discover the minimum economic field size, estimate the volumes that may remain untested updip, and maximize the expected monetary value of the exploration project. During postmortem evaluations (look-backs), it is important that well outcomes are compared with relevant pre-drill well assessments.

A drilling technology guided by well-seismic information integration

Abstract The predictions by drilling-related mechanical and geological models are in some degree inaccurate due to non-unique solution of seismic velocity model. To address this problem, a new drilling technology guided by well-seismic information integration is proposed which consists of seismic velocity update of drilled formations, seismic velocity prediction of the formation ahead of drilling bit, and the prediction of geological feature and drilling geological environmental factors ahead of bit. In this technology, real information (velocity, formation and depth) behind the drilling bit and local pre-stack seismic data around the wellbore being drilled are used to correct the primitive seismic velocity field for a re-migration of seismic data and to update geological features and drilling geological environmental factors ahead of the drilling bit. Field application shows that this technology can describe and predict the geological features, drilling geological environmental factors and complex drilling problems ahead of the bit timely and improve the prediction efficiency and accuracy greatly. These new updated results are able to provide scientific basis for optimizing drilling decisions.

Probing crustal anisotropy by receiver functions at the deep continental drilling site KTB in Southern Germany.

ABSTRACTSeismic anisotropy is a unique observational tool for remotely studying deformation and stress within the Earth. Effects of anisotropy can be seen in seismic data; they are due to mineral alignment, fractures or layering. Seismic anisotropy is linked to local stress and strain, allowing modern geophysics to derive geomechanical properties from seismic data for supporting well planning and fracking. For unravelling anisotropic properties of the crust, the teleseismic receiver functions methodology has started to be widely applied recently due to its ability in retrieving the three‐dimensional characteristics of the media sampled by the waves. The applicability of this technique is tested here by a field test carried out around the Kontinental Tiefbohrung site in southeastern Germany. We compare our results to previous investigations of the metamorphic rock pile of the Zone Erbendorf‐Vohenstrauss, drilled down to 9 km depth, which sampled an alternating sequence of paragneiss and amphibolite, in which a strong foliation has been produced by ductile deformation. The application of the receiver functions reveals the presence of two distinct anisotropic layers within the metamorphic rock pile at 0–4 km and below 6 km depth, with up to 8% anisotropy; the depth of these two layers corresponds to the location of mica‐rich paragneiss which show intense foliation, and finally proves the relation between the signal in the receiver functions, rock texture and presence of cracks. We have now the capability of providing insights from passive seismic data on geomechanical properties of the rocks, useful for geological exploration and engineering purposes, which will help influencing expensive drilling decisions thanks to future application of this seismic technique.

Introduction to this special section: AVO inversion

It has been more than three years since The Leading Edge last published a special section on amplitude variation with offset (AVO) inversion, and interest in the subject remains strong. This past spring, SEG hosted a joint symposium in Houston, Texas, on the “Resurgence of seismic inversion,” and the body of talks and case studies demonstrated the method's continued relevance to making impactful drilling decisions. Despite this, and despite AVO inversion's position as a mature and well-established technique, there are an abundance of examples in which inaccurate AVO predictions have led to drastic failures at the drill bit. This highlights the challenges that still exist in the successful execution of such investigations and makes the subject occasionally controversial and certainly fraught with data-quality and best-practice considerations. In this vein, the special section presented here offers examples of the broad sweep of considerations and methods relevant to enabling successful AVO inversion and the interpretation of its products, as well as case studies that demonstrate how application of the technique can be impactful all the way through to appraisal and field development programs.

A SPECTRAL METHOD OF LITHOFACIES DIFFERENTIATION WITHIN A HYDROCARBON RESERVIOR UNIT USING SEISMIC AND WELL DATA FROM TOMBOY FIELD NIGER DELTA

Seismic facies analysis is a key component of Seismic interpretation workflow, as much information on depositional process, environment, reservoir architecture and potential can be determined from the seismic data. This enhances the seismic visibility of subtle stratigraphic features, and prediction of new prospects for drilling due to lateral continuity of sand bodies (the hydrocarbon reservoir) deposited within the sedimentary column. This study presents the results of the application of seismic amplitude inversion and spectral decomposition to differentiate lithofacies within a thin-sand reservoir and show their lateral and vertical continuity using amplitude-derived attributes (rock properties) in the interpretation of 3D seismic and well log data from “TOMBOY” field Niger Delta. A thin-sand reservoir was delineated from lithologic log signatures within the interval 11,135.61-11,210.35ft which corresponds to the time window 2.752 - 2.768secs on the seismic data along an arbitrary line drawn to connect the six wells (01-06) in the field. Crossplot of acoustic impedance against density across the reservoir bed showed three compartments interpreted as gas filled sand, oil filled sand and shale. The interpretation was enhanced via spectral analysis by computing frequency maps of acoustic impedance, density and velocity using discrete Fourier transform (DFT) technique at top (2.752sec) of the reservoir in terms of magnitude, phase and frequency. Phase response for the three attributes (acoustic impedance, density and velocity) showed lateral continuity and discontinuity of sand lithofacies at the various well locations which were not evident on their original amplitude time slice, while frequency response showed bed thickness, with low frequency indicating presence of hydrocarbon or sand rich beddings, while high frequency indicates thin shale beddings. It was observed that the top (2.752sec) of the reservoir for wells 02, 05, 01 and 04 showed low frequency values for the three attributes (acoustic impedance, density and velocity) which indicates potential zones for hydrocarbon production and development in the field, while wells 03 and 06 within the same time slice (2.752sec) showed a higher value in acoustic impedance frequency, density frequency and velocity frequency and suggests the presence of thin shale facies at the top (2.752sec) of the thin-sand reservoir. By defining the lateral and vertical continuity of sand facies within the reservoir bed, hydrocarbon fairways were better defined and knowledge of this can be incorporated into drilling decisions for field development. The results gave enhanced structural disposition of the reservoir bed and more insights into the variation of sand lithofacies with depth. Keywords: Lithofacies, Amplitude inversion, Geologic transform, Seismic attributes, Cross plots and Spectral decomposition. DOI : 10.7176/JEES/9-3-14 Publication date :March 31 st 2019

Addressing the Community Impact of Forced Pooling on Local Drilling Decisions

Increased unconventional oil and gas development has created concerns about property right issues and land degradation problems for many U.S. landowners. Many states allow "forced pooling," which forces landowners to lease their lands to an operator, even if the owner disagrees, when a threshold is reached. Extension professionals need to provide relevant information to decision makers and other local stakeholders on the effects of forced pooling. This article examines how forced pooling laws can affect local voice. Findings suggest that the holders of decision-making power at the local level differ according to the forced pooling thresholds used.

3D Seismic Reflection Amplitude and Instantaneous Frequency Attributes in Mapping Thin Hydrocarbon Reservoir Lithofacies: Morrison NE Field and Morrison Field, Clark County, KS

Thin hydrocarbon reservoir facies pose resolution challenges and waveform-signature opportunities in seismic reservoir characterization and prospect identification. In this study, we present a case study, where instantaneous frequency variation in response to a thin hydrocarbon pay zone is analyzed and integrated with other independent information to explain drilling results and optimize future drilling decisions. In Morrison NE Field, some wells with poor economics have resulted from well-placement incognizant of reservoir heterogeneities. The study area in Clark County, Kanas, USA, has been covered by a surface 3D seismic reflection survey in 2010. The target horizon is the Viola limestone, which continues to produce from 7 of the 12 wells drilled within the survey area. Seismic attributes extraction and analyses were conducted with emphasis on instantaneous attributes and amplitude anomalies to better understand and predict reservoir heterogeneities and their control on hydrocarbon entrapment settings. We have identified a higher instantaneous frequency, lower amplitude seismic facies that is in good agreement with distinct lithofacies that exhibit better (higher porosity) reservoir properties, as inferred from well-log analysis and petrographic inspection of well cuttings. This study presents a pre-drilling, data-driven approach of identifying sub-resolution reservoir seismic facies in a carbonate formation. This workflow will assist in placing new development wells in other locations within the area. Our low amplitude high instantaneous frequency seismic reservoir facies have been corroborated by findings based on well logs, petrographic analysis data, and drilling results.

Optimizing Infill Drilling Decisions Using Multi-Armed Bandits: Application in a Long-Term, Multi-Element Stockpile

Mining operations face a decision regarding additional drilling several times during their lifetime. The two questions that always arise upon making this decision are whether more drilling is required and, if so, where the additional drill holes should be located. The method presented in this paper addresses both of these questions through an optimization in a multi-armed bandit (MAB) framework. The MAB optimizes the best infill drilling pattern while taking geological uncertainty into account by using multiple conditional simulations for the deposit under consideration. The proposed method is applied to a long-term, multi-element stockpile, which is a part of a gold mining complex. The stockpiles in this mining complex are of particular interest due to difficult-to-meet blending requirements. In several mining periods grade targets of deleterious elements at the processing plant can only be met by using high amounts of stockpiled material. The best pattern is defined in terms of causing the most material type changes for the blocks in the stockpile. Material type changes are the driver for changes in the extraction sequence, which ultimately defines the value of a mining operation. The results of the proposed method demonstrate its practical aspects and its effectiveness towards the optimization of infill drilling schemes.

Real-Time Pore Pressure Detection: Indicators and Improved Methods

High uncertainties may exist in the predrill pore pressure prediction in new prospects and deepwater subsalt wells; therefore, real-time pore pressure detection is highly needed to reduce drilling risks. The methods for pore pressure detection (the resistivity, sonic, and corrected d-exponent methods) are improved using the depth-dependent normal compaction equations to adapt to the requirements of the real-time monitoring. A new method is proposed to calculate pore pressure from the connection gas or elevated background gas, which can be used for real-time pore pressure detection. The pore pressure detection using the logging-while-drilling, measurement-while-drilling, and mud logging data is also implemented and evaluated. Abnormal pore pressure indicators from the well logs, mud logs, and wellbore instability events are identified and analyzed to interpret abnormal pore pressures for guiding real-time drilling decisions. The principles for identifying abnormal pressure indicators are proposed to improve real-time pore pressure monitoring.

4D Seismic over the Pyrenees Fields

In this paper we present a case study of 4D seismic acquired over the Pyrenees Fields, offshore Western Australia. The Pyrenees trend was discovered with the drilling of the West Muiron-5 discovery well in 1993 which found oil and gas within the Pyrenees member sandstones. Production at Pyrenees started in 2010. Before the start of production, a dedicated 4D baseline survey was recorded over the fields in 2006. A detailed modelling study concluded that a 4D monitor survey would provide useful information for reservoir surveillance and infill drilling decisions. The monitor survey was acquired in 2013, and the overall quality of the 4D was excellent with high 4D signal strength and low 4D noise. The 4D response at Pyrenees is broadly consistent with the modelling. The main response is softening of the reservoir caused by gas coming out of solution produced by a pressure drop within the reservoir. The 4D response to changes in oil saturation is small. Incorporating the 4D interpretation into field development is ongoing, and so far it has been useful for refining the stratigraphic model, determining fault seal integrity, and determining the sealing capacity of intra-field faults.

Elastic full-waveform inversion application using multicomponent measurements of seismic data collection

Recent computational improvements allowed us to simulate elastic wavefields in a 3D manner and undertake the challenge of executing elastic full-waveform inversion (EFWI). The 3D SEG/EAGE overthrust synthetic data were used to run the initial tests, which included using all three components for the simulation. The inversion targeted two regions: the channel system and the overthrusted zone, which proved the effectiveness of EFWI to delineate geology in terms of [Formula: see text] and [Formula: see text] velocity fields. For the field data experiment to demonstrate the technologies, we elected to use a Gulf of Mexico ocean bottom cable data set, which allowed us to take advantage of relatively large offsets along with the 4C acquisition. The input data were minimally processed mostly through noise removal, and the initial model was a Gaussian smoothed version of grid tomography output, which is done by a prestack migrated gather flattening process. During EWFI, a multiscale approach was followed to ensure convergence, and the early stages of the [Formula: see text]/[Formula: see text] ratio were constrained by the mud rock-line ratio. When the last sets of inversions were executed, this constraint was eliminated to ensure the simultaneous update of the [Formula: see text] and [Formula: see text] velocity fields. The density was kept constant to keep the inversion at a simple level, which allowed us to draw essential conclusions. The velocity fields were validated through an imaging algorithm of the elastic reverse time migration, and the imaging shows clear structural improvements when inputting the inverted velocities in conjunction with the measurements. If full-waveform inversion can provide multiple earth parameters, the user can use the process to detect gas zones along with sand and shale content of the subsurface, which will further assist the drilling decisions. We achieved this by simulating the earth more accurately with the elastic wave propagation in the algorithms.

Walkaway VSP - Going beyond imaging

Simultaneous AVO inversion of seismic data is an integral part of oil and gas exploration. Traditionally this technique is applied to surface seismic data, relying on availability of various angle stacks as well as on presence of offset wells for low frequency models. This paper investigates how a Walkaway Vertical Seismic Profile (WVSP) can be utilized for localized AVO inversion. Traditionally WVSP are designed for one of the following three purposes: imaging, anisotropy and AVO/AVA analysis. This paper shows a set of conditions that allow for WVSP data to be inverted following a commonly utilized simultaneous seismic inversion technique. The advantage of performing a localized WVSP AVO inversion is that low frequency models are measured during WVSP acquisition. This significantly reduces the ambiguity of the background models for inversion. Another advantage is that the inversion input derived during WVSP migration comes from measured vertical velocities, thus allowing more accurate angle stacks, thus improving the quality of the inversion. Lastly, WVSP images are generally of higher frequency content, thus producing high frequency density, Acoustic Impedance and VpVs images in the vicinity of the wellbore. The results can assist in calibrating the surface seismic inversion once more well data are available as well as making quick drilling decisions for deepening or side tracking wells.

Unearthing New Layers - Crosswell Seismic Redefines Seismic Imaging in Bunyu Field, Indonesia

Surface seismic is fundamental information for reservoir mapping and in-fill drilling decisions. A good seismic is critical to successful development of a field. However, at times, the surface seismic is of degraded quality due to various reasons which makes the mapping and interpretation of the reservoir layers difficult and uncertain. Near-surface conditions such as topography, weathering layer adversely affect the surface seismic data acquisition & processing. In Bunyu field in Indonesia, problem is further compounded by the presence of near surface coal seams which renders seismic to be of poor quality. In order to optimize the field development and boost recovery, enhanced seismic is seen as a fundamental requirement to make informed in-fill drilling decisions. Crosswell seismic provides high resolution imaging of the subsurface at the reservoir scale. The technology is used for delineating complex structure. It is not affected by the surface conditions as the transmitter and receivers are deployed downhole in separate wells, providing velocity tomogram and reflection imaging between the wells. Bunyu Field in East Kalimantan is on production since 1950 with declining production over the years. It is primarily a discontinuous sand-shale sequence with shallow coal layers. The existing 3D seismic is of poor quality which makes reservoir interpretation very uncertain. It is difficult to map these channel sands due to poor seismic. Crosswell seismic was thus acquired to complement the 3D seismic information for informed infill drilling decisions and field optimization. Crosswell seismic has provided a dramatic improvement in seismic imaging even at large interwell distances and will be helpful in delineating reservoir and ultimately aid in better in-fill drilling.

Optimizing EM data acquisition for continental shelf exploration

The controlled-source electromagnetic (CSEM) method has been applied to oil and gas exploration and production for more than 10 years. During this time, most of the focus has been on derisking deep- and ultradeep-water drilling decisions. In this article, we will consider how EM methods can be optimized for continental shelf applications, which represent approximately 80% of offshore discoveries. Historically, applications of EM on the continental shelf have been limited for two principal reasons:

Managed-Pressure Drilling: Beyond the Conventional Limit in a Deepwater HP/HT Well

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 142312, ’Managed-Pressure Drilling Enables Drilling Beyond the Conventional Limit in a Deepwater HP/HT Well,’ by F. Kernche, D. Hannegan, SPE, E. Sammat, and M. Arnone, SPE, Weatherford, prepared for the 2011 SPE Offshore Europe Oil and Gas Conference and Exhibition, Aberdeen, 6-8 September. The paper has not been peer reviewed. Managed-pressure drilling (MPD) was used successfully on an offshore high-pressure/high-temperature (HP/HT) well. Wells in this field and other offset wells in the area had faced many problems including inadequate mud management resulting from depleted or overpressured zones, influxes, mud losses, and differential sticking. This well was drilled with a proprietary MPD system that is a closed-loop method of monitoring and controlling flow and pressure. Introduction MPD uses a closed and pressurized drilling-fluid (mud) circulating system that facilitates drilling with precise management of the wellbore-pressure profile. The primary objective of MPD is to optimize drilling processes by decreasing nonproductive time (NPT), mitigating drilling hazards, and enabling the drilling of otherwise technically or economically undrillable highly complex prospects. Because MPD addresses NPT, the technology is of greatest potential benefit to expensive offshore-drilling programs. Although MPD was been practiced safely and efficiently from all types of offshore rigs, yielding the desired results, it still is considered a relatively new technology to many offshore drillers. The uptake in offshore MPD applications is, in part, because drilling is taking place in greater water depths, through depleted zones or reservoirs, and into narrow or relatively unknown equivalent-mud-weight (EMW) drilling windows. Technical Justification The application of MPD technology can optimize the drilling process by decreasing NPT and mitigating drilling hazards associated with conventional drilling techniques. Most importantly, the MPD system reduces drilling costs and limits drilling-cost uncertainty by: Avoiding conventional-drilling NPT problems, such as lost circulation, shale instability, kicks, nuisance-gas zones, and differential sticking. Increasing the rate of penetration, increasing bit life, and decreasing trip frequency. Enabling access to potential assets/reservoirs previously believed to be undrillable by improving health, safety, and environmental (HSE) conditions. MPD System The MPD system used in this specific application consisted of a proprietary control algorithm to identify influxes and losses on a real-time basis and a choke at surface to apply backpressure to maintain well control. The system allows making drilling decisions on the basis of actual pressure and flow data rather than by use of predicted downhole parameters based on hydraulic models, and it provides real-time monitoring of the well-bore parameters while drilling.