bluuebunny/crossref_metadata_2025 huggingface dataset:
Formation Evaluation from Logging While Drilling Prospective the Effects of Drilling Dynamics and Environment, Case Study from Abu Dhabi
Authors: Soliman Ahmed Mohamed , Khairy Hamad Awad , Elabsy Islam , Deng Lichuan , Ali Taif Yousif , Nazlan Firdaus
Published: October 2022

Wireline (WL) measurement emerged a long time before the logging while drilling (LWD) technology which created generations of petrophysicists with different school of thoughts. With the dramatic increase in the adoption rate of the advanced LWD technologies, highlighting the logging environment effects and revisiting our understanding of the formation responses logged under different borehole conditions are more critical than ever.

Hundreds of LWD datasets from various environments have been reviewed to identify its effects on data quality and responses from bottom-hole-assembly (BHA) design, driving mechanism, tool eccentricity, well angle, mud properties, differential invasion, borehole condition, formation fluid properties, and drilling fluids interactions. Some of these effects co-occur on many occasions, complicating the log response. Examples and demonstrations of our understanding and interpretation of these phenomena are discussed in the study.

Looking to the reservoir in the relatively fresh state, a few minutes after drilling with an understanding of the logging environment provides a unique opportunity to obtain precise formation evaluation and insight into reservoir behavior when combined with different time laps acquisitions.

This work is a continuation and addition to (Parmanand et al., 2018) which was extended to include more environmental factors in different oil fields and reservoirs with more advanced LWD technologies.

This work summarizes the long cumulative experience of interpreting LWD measurements, shares the main observations related to LWD responses and serves as a ready reference to identify measurement artifacts from actual formation responses. It is helpful as a reference guidebook for log analysts, geologists, geo-steering engineers, and others.
Slimhole One Piece Matrix Design Bit Technology Showed Significant Integrity and Performance Improvements in Coil Tubing Operations in Middle East
Authors: Rojas Pablo , Quintero Jonathan
Published: October 2022

Objectives/ Scope

This paper describes a new innovative concept, using a one-piece matrix slimhole design for a 3.625’’ PDC bit. This significantly increases durability and reliability, enhancing the bit life in multiple test analysis in highly abrasive lower Permian sandstone, driven by turbine and coiled tubing. The collaboration between the national oil company (NOC) and the drill bits provider results in achieving consistent records in footage and rate of penetration, without compromising bit integrity previously seem in sleeve designs.

Methods, Procedures, Process

A matrix sleeve design is the result of creating a single piece of bit using 100% matrix material adding TSP (Terminally stable Polycrystalline) in the gage pad protection, instead of using standards steel sleeve design with diamond grid discs protection. This concept allows the matrix sleeve to eliminate the cracks observed in the standard steel sleeve due the high temperatures generated while drilling into high abrasive sandstone environment with extreme parameters of rpm (1800 - 2000) as the turbine output. This provides enhancement to bit durability and integrity, due to the innovative use of higher resistant materials.

Results, Observations, Conclusions

After the first introduction, a qualifying trial test process starting in January and completed in September 2020, a microstructure evaluation was performed to evaluate the present of any field service cracks in the proposed one-piece matrix design, followed by full field deployment completing 12 wells in three different major fields. This resulted in setting the benchmarks of higher average footage of 354.61 ft (>50% of improvement) and average penetrations rate of 14.44 ft/hr (>25% of improvement) in abrasive drilling environment with zero integrity or reliability issues reported. After the deployment, each one-piece matrix bit has been physically inspected using the standard IADC dull grading format. More details of the performances, and bit inspections, will be presented in this paper.

Novel/Additive information

The innovative concept of using a one-piece matrix bit design delivers a much more reliable and efficient new technology, which significantly increased performance and successful deployments across this difficult drilling environment in these unique wells drilled in the Middle East.
Using In-Bit Data Capturing Sensors to Identify and Reduce Dysfunctions Using a Higher Drilling Efficiency Shaped Cutter Solution
Authors: Kouzaiha Rami , Sayyaleh Salem , Khalil Ahmed , Borayek Ahmed , Reyad Mahmoud , Al Otaibi Atheer
Published: October 2022

Drilling oil wells with long laterals in extended reach reservoirs present one of the hardest challenges for drilling companies in the demanding environment especially given their propensity to high downhole vibrations causing many premature tool failures. Managing to attenuate these sources of vibrations can lead to reduced drilling risks and lower section times with less exposure to reservoir hazards. Through a downhole vibrations study using in-bit sensor captured data along with a force simulations model between the drill bit and the formation, lower vibrations are expected with improved drilling efficiency.

Understanding the drilling vibrations using a high frequency reading sensor placed in the bit is the key to differentiate the types and excitation sources of dysfunctions downhole in order to quickly and effectively address and reduce them through parameter optimization and drill bit design modification. The 6 1/8" lateral section drilled with a standalone push the bit Rotary Steerable System (RSS) was studied deeply to understand the types of vibrations coming from the bit to attenuate any identified dysfunctions. The high frequency readings in this drilling application demonstrated high stick and slip vibrations typically excited from the increased engagement of Polycrystalline cutters into the formation which led to increased BHA vibrations and lower rates of penetration (ROP) increasing well time and cost. Mitigating this destructive dysfunction caused in part by certain drilling limitations of the conventional round PDC cutter was found to be the key to a higher drilling efficiency with lower vibrations and improved stability extending the life of the bits and the downhole tools. This led to an overall decrease in section drill time and an increase in the consistency of well delivery.

Point loading shaped cutters with an adapted drill bit design profile were used in several lateral wells in MENA. The new bit attenuated the overall torsional related dysfunctions in the section by 15% and producing more efficient drilling which resulted in an improved average ROP of the lateral section by 34% as well as a reduction in the rate of downhole tool failures from 11% to less than 7%. Using image recognition technology to assess, analyze and digitize the bit dulls, each cutter on the bit was evaluated, and the new bit design illustrated a 9% improvement in the average dull with a lower requirement for bit repair.

The digitally enhanced drill bit design with the point loaded shaped cutters enabled a pre-fracturing of the formation while also benefitting from the shearing mechanism of the shaped PDC cutters enhancing the overall drilling efficiency of the bit. These shaped cutters also added stability to the bit which resulted in reduced overall drilling dysfunctions and extending the BHA life along with an improved section ROP.
Intelligent Pipe: A Multi-Annuli Monitoring Solution
Authors: Bulard Francois-Xavier , Tavernier Emmanuel , Kling Lucas
Published: October 2022

Well integrity has always been a challenge for the oil and gas industry. The main concern for operators is to prevent catastrophic well failure during their operations, which could have a dramatic impact on the environment and put people working on site at risk. The industry is therefore looking for new solutions to monitor well activity in real time, especially for subsea wells where the annuli are inaccessible. By anticipating any abnormal behavior, operators will then be able to act faster and adapt their operations to avoid any damage to the well.

The multi-annulus monitoring solution will provide pressure and temperature for each well annulus. These key parameters are captured by innovative sensors based on MEMS technology. An innovative transmission methodology is used that allows power supply and data retrieval even for annuli beyond the "B-annulus". All electronic elements of the solution will be qualified through the international recommendation (called AWES) which consists of a series of mechanical and long-term tests to ensure that our system will survive for 20 years at 125°C.

This paper will present the results of the different tests carried out to qualify the electronics, those performed to qualify the performance of the multi-annulus transmission, as well as the results of the first field trial carried out with this product. During this first trial, the operator encountered several operational issues. Our system provided actual data that was used in their own simulation to investigate the root causes of these operational difficulties. This clearly demonstrated the importance of having data from inside the well to confirm and complete the well simulation. This article describes the development of a continuous monitoring solution through to its deployment.

This system offers oil and gas operators a new tool to monitor their wells and enhance the safety of their operations. It could be used in all storage applications, especially those related to the energy transition, including CCS and H2 storage.
Enhanced Single Trip Upper Completions for ERD Applications
Authors: Parihar Shardul , Wang Zhihua , Andrew Wills John , Mason Jane
Published: October 2022

An Abu Dhabi offshore field development plan comprises of ERD wells requiring intermediate / production casing depths of up to 23,000 ft with horizontal sail sections of approximately 10,000 ft of length. The original completion design involved drill pipe deployed intermediate completions, followed by a separate upper completion run with anchor latched seals. Over time, operational practices enabled the use of single-trip completions with tubing mounted packers, saving 2 – 3 rig days per well, but introduced some challenges. The objective was to maximize the usage of single-trip completions while continuing to leverage the advantages of an intermediate completion. Additionally, deployment enhancers such as lubricated fluid, low drag centralizers, and / or upsized tubing were included in the design to extend deployments deeper.

A comprehensive application review was conducted covering the system technical limits during installation and well life cycle operations. Detailed testing and modelling were carried out to understand the impact of deployment enhancers. This paper will provide insight as to the detailed drivers and design of the lubricated fluid and low drag centralizers. Additionally, the strategy for well trials and their successful results will be covered.

Several enhanced single-trip completion systems were successfully installed, confirming the efficiency gain of 2 – 3 rig days per well in high angle, deep casing ERD wells. The fluid lubrication provided 30 – 50% cased hole friction factor reduction. Additional long term well life cycle efficiencies were achieved, such as OPEX savings during future workover operations resulting from the anchor-latch feature and maintaining the same ID from the production packer down to the liner for future lower completion retrofit without requiring the production packer to be retrieved.

While single-trip upper completion systems have been used in the past, achieving the two-trip completion system advantages with a single-trip system was not possible before. Additionally, deploying the enhanced system coupled with deployment enhancers has allowed the completion of high angle and deep

casing ERD wells. Expectations are to extend application of this completion design to even deeper casing depths.
Quantifying Smart Liner Acid Stimulation Efficiency in Heterogeneous Carbonate Reservoir Using Inline Tracers and PLT
Authors: Bazuhair Ahmed , Mogensen Kristian , Al-Marzouqi Laila , Mustafa Hammad , Chitre Sunil , Al Maazmi Mariam , Gadelhak Abdelrahman , Al Jawhari Mohamed
Published: October 2022

Matrix-acid stimulation is a key production enhancement technique for carbonate reservoirs. The ability to control acid placement by diversion along the reservoir section is often challenging, particularly for heterogeneous formations where low-permeability intervals may remain under-stimulated. In this paper, we demonstrate via subsequent inflow profiling that efficient stimulation of both low- and high-permeability segments can be achieved using a completion method called a Smart Liner and a new methodology of downhole flow monitoring without operational well intervention by utilizing inline tracer system across the lower completion.

The Smart Liner is a completion technique, which relies on a number of small and unevenly spaced holes to divert acid along a horizontal drain, while incorporating swellable packers to isolate segments with different reservoir properties. The hole spacing design is unique for each well and requires a software algorithm to balance the outflow. The inflow monitoring is assessed through both inline chemical tracers and conventional PLT. Main components of this algorithm has been presented in an earlier publication.

The inline tracer system can provide "wireless" continuous production profiling without the risk & cost associated with conventional PLT methods. The inline tracer samples were collected during both stages of pre-stimulation and post-stimulation activities on oil producer wells, which shows downhole contribution of all segments, acid arrival and enhancement of Mid section of the reservoir drain. Moreover, PLT was conducted to validate inline tracer results.

Past deployments of Smart Liners have targeted homogeneous reservoir intervals, but in this paper, we show that also reservoirs with significant permeability variation can be effectively matrix-acid stimulated. It is to our knowledge the first time that inflow profiling of a long horizontal well has been probed with inline tracers as well as PLT. Furthermore, we quantify the incremental impact of a given acid volume on injectivity based on the high-frequency data from the stimulation job.
An Innovative Method to Enable Well Kick-Off and Liquid Unloading Using Dry Ice
Authors: Karadkar Prasad , Alkhowaildi Mustafa , Bulekbay Aslan
Published: October 2022

Gas production can be enhanced by the unloading of liquid accumulated in the wellbore. Conventionally, it is addressed by dropping soap sticks into a gas well. The foamability of soap sticks tends to decrease in the presence of condensate. Alternativity, well can be kicked-off by using N2 lifting but it is an expensive method that involves coil tubing operation. In this paper, an innovative and simple method of unloading a condensate-bearing gas well using dry ice is described.

Gas wells accumulated with liquid or condensate can be unloaded by displacing it with CO2 gas. It also helps to reduce hydrostatic pressure during kick-off well. Dry ice pellets can be inserted inside the wellbore, which can be settled down by gravity and CO2 gas formation inside the wellbore due to dry ice sublimation. The dry ice sublimation rate can be restricted by encapsulating it with self-degradable polymers that can be hydrolyzed inside the wellbore. Cylindrical dry ice pellets from the food industry having a half-inch diameter and a couple of inches long were used in this work.

Dry ice is the solid form of CO2 having an expansion ratio of 1 to 554 for solid to gas at sublimation point −78.5 °C and atmospheric pressure. The density of dry ice is 1.562 gm/cm3. A series of lab experiments were conducted to show CO2 gas generation from dry ice in the water. After inserting a dry ice pellet into the water column, it settled down at the bottom and started releasing CO2 gas with a sudden expansion in volume. CO2 foam was also generated by inserting dry ice pallets with foaming agents inside the water column. The release of CO2 gas in the wellbore and foam generation can assist in decreasing hydrostatic pressure and lifting liquid inside the wellbore. At the well site, a simple modification is required to insert dry ice into the wellbore. The cylindrical chamber needs to be installed above the master value of the Christmas tree. This is described in the paper with the procedure to follow during the operation. A mathematical tool has been developed to estimate the amount of dry ice pallets required for a given well geometry. For 4.5 inch, 1000 ft long production tubing, 1000 kg dry ice can release 51.7 bbl of CO2 gas, which can generate a 495 psi increase in pressure.

Well intervention operations are complex and expensive processes. It is preferred to use simpler, quicker, safer, and more cost-effective methodologies. The use of dry ice to unload gas well is simple, cheaper and an innovative solution. The release of CO2 gas from dry ice can offer additional benefits such as better and faster cleanup and the removal of condensate blockage in the near-wellbore area.
Development Mechanism of Ultra-Low Permeability Limestone Reservoirs: A Case Study of the Cretaceous S-Reservoir in H Oilfield, Iraq
Authors: Ning Chaozhong , Deng Xili , Liao Xuan , Wang Youjing , Zhu Guangya , Han Haiying , Yang Jing , Chen Jiaheng , Wang Nai , Li Nan , Lan Yukun , Zhu Changqian , Peng Shudai , Shao Lei
Published: October 2022

Ultra-low permeability limestone reservoirs in the Middle East have huge untapped reserves. In Iraq, Field H has nearly one quarter of reserves in the S-Reservoir with permeabilities of (0.02-0.4 mD). It is difficult to identify optimal drilling locations, or sweet spots, that maximize recovery factors due to poor understanding of reservoir characteristics. Using the S-limestone reservoir, this study aims to clarify the environment of deposition, diagenetic evolution, reveal the development mechanism of ultra-low permeability, and predict the distribution of more favorable areas.

Whole core, thin sections, scanning electron microscope (SEM), mercury injection (MICP), well logs, and seismic data were utilized for the analysis. Through core and thin section observation, lithology, biostratigraphic sequences, pore type, and sedimentary structures were determined. Through these observations the environment of deposition of the S-Formation is interpreted as mid to outer carbonate ramp. The lithology is mainly wackestone to packstone deposited in a low energy environment below fair weather wave base. Primary fossils are planktonic foraminifera tests as grains and coccolith microfossils in the matrix.

Thin sections and MICP analysis helped delineate the porosity classes and diagenetic history. The pore throat size, determined by MICP data, was 0.03 - 0.1 μm. Primary porosity is around 10-25% and is driven by intragranular voids in foraminifera tests, followed by intergranular, and intercrystalline microporosity of the matrix. Foraminifera tests are generally intact and float in the mud matrix. As a result, large intragranular pores are well developed but not connected, causing overall medium-high porosity but ultra-low permeability. Early marine calcite cement is the primary diagenetic process which destroyed porosity and permeability. Little to no evidence of secondary dissolution was observed.
Identification of Trends Driving Reservoir Heterogeneity at Multiple Stratigraphic Intervals in a Giant Middle Eastern Carbonate Reservoir.
Authors: Sellar Christopher , Contreras Perez David Rafael , McGeer Alicia , Al Mansoori Maitha Mubarak , Vršic Aleš
Published: October 2022

Oilfield A is a low relief structure consisting of multiple stacked reservoirs. Three reservoir intervals show different trends of reservoir property distribution. Lateral reservoir property degradation in Oilfield A is correlated to increased vertical heterogeneity. Understanding the driving mechanism for the controls on reservoir property distribution is therefore essential for effective well placement, well spacing and achieving the expected ultimate recovery from the oilfield.

Previous integrated reservoir characterization studies in Oilfield A have identified a link between chemical compaction, reservoir thickness, cementation and reservoir property distribution in Reservoir 2. As part of reservoir model building and subsequent structural updates, thickness maps have been constructed from well data for each reservoir unit as an early indicator of possible reservoir property trends. The maps show trends which are integrated with other data, both static and dynamic in order to validate their impact. To establish correlations, thickness maps were compared to maps of log porosity, facies, diagenetic features, geophysical attributes, cumulative oil production and water cut.

Reservoir thickness shows a good correlation to reservoir property distribution in several different reservoirs in Oilfield A. Reservoir 3 shows a south-east to north-west trend of reservoir degradation, Reservoir 2 shows a north to south trend of reservoir degradation, while Reservoir 1, shows a west to east trend of reservoir degradation.

Chemical compaction has been shown to drive reservoir property degradation in all three reservoirs. An increased abundance of stylolites is noted in the thinnest, most cemented, poorest quality parts of the three reservoirs. Since chemical compaction (stylolitisation) is a process which starts in the burial diagenetic realm and since all three reservoirs show a similar paragenetic history it is logical to expect all three reservoirs have a similar burial history. However, the trends observed in the three stacked reservoir intervals are orthogonal to opposite.

Reservoir properties are rarely randomly distributed in oil reservoirs. Integrating static and dynamic data together in Oilfield A has shown that compaction is the dominant driver of reservoir degradation in three stacked reservoirs. Understanding the trends controlling lateral and vertical reservoir heterogeneity due to compaction is essential in appraisal and development well planning as well as increasing expected ultimate recovery as part of increased and enhanced oil recovery projects.
New Exploration Plays in Sohar Basin UAE
Authors: Williams Glen , Thurley Callum , Cox Edward , Stewart Donald Neil , Sarssam Mark , Al Hamadi Masoud
Published: October 2022

The Sohar Basin, located offshore the East Coast of the Arabian Peninsula, is a long-ignored area adjacent to the super basins of the Arabian Plate. Three dry wells were drilled in the northern Sohar Basin between 1969 and 1980 on structural anomalies. In 2001, a 3D survey was acquired over the UAE portion of the basin in the belief that the Arabian Platform Carbonates extended from the Rub al Khali Basin, beneath the Semail Ophiolite to the east. This study depicts how this legacy 3D dataset has been re-evaluated to define new prospectivity.

A tectonic history defined by a sequence stratigraphic and structural interpretation of the 3D data as well as a basin modeling exercise has revealed a previously unexamined petroleum system. These include Miocene to Eocene-aged turbidite channel and fan complexes representing potential reservoir units. In the deeper section, high reflectivity layers within ‘mini-basins’, have seismic characteristics consistent with organic rich source rock layers. Basin modelling indicates that these layers would be mature for hydrocarbon generation. Shallow bright spots provide evidence for hydrocarbon migration along deep-seated faults.
Abu Dhabi Fold-Thrust Belt Dilemma of Jebel Jais Outcrops: Impact on Hydrocarbon Trapping Mechanism in Eastern Abu Dhabi
Authors: Noufal Abdelwahab , Aamir Muhammad , Obaid Khalid , Al Ali Ibrahim , Al Hosani Ismail
Published: October 2022

For the last decades, only a few scattered wells have explored the thrust fold belt in Abu Dhabi, with inconclusive results about the hydrocarbon potentiality. Drilling was avoided in these areas in the past due to the geological complexity and unavailable technologies that would reveal the subsurface geometries. Previous studies attempted to resolve the petroleum system elements in Eastern Abu Dhabi; however, they are still challenging, and require thorough investigation.

This paper is focusing on the integration of Jebel Jais outcrops in Ras Al Khaima with subsurface datasets (Geophysical and well data), which will help in understanding the subsurface structural trap geometries, reservoir and charge evolution and timing. The outcrops functioned as remarkable analogues for structural features that indicate complex tectonics of the region such as folding and faulting. They will also serve in guiding the mechanical and kinematic modeling of subsurface, where seismic image is undistinguishable.

ADNOC has recently completed a Mega 3D seismic survey in Eastern Abu Dhabi with higher acquisition parameters compared to the legacy 2D and 3D seismic surveys. The early fast track Seismic processing results revealed additional structural styles, which will be refined with advanced seismic imaging techniques, and calibrated with potential data such as gravity and magnetics in later stages.

The thrust nappes deformation and the fault-bend folds were observed in the outcrops. Most of thrusts are associated with strike-slip component and the detachment surface located at the base of Khuff units. Folding-stacked structures have different orientations with narrow duplexes that led to the growth of anticlinal stacked structures, which were the consequence of differential uplift of the rock units above the duplex, and were subjected to stretching. This process invoked strike-slip faulting along the lateral culmination wall and was facilitated by the regional, syn-thrusting arc–parallel transpression. Horizontal movement along the fault plane is a result of tear faulting accommodating a varied rate of advancement of Khuff units. The time of the fault formation is well-constrained post-Jurassic; however, the syn-thrusting origin showing its anticipation through Triassic onwards forming thrust-fold belt.

This paper will provide insights from Jebel Jais Outcrops that will help in understanding the substantial undiscovered hydrocarbon resources and prepare for future exploration activities.
Successful Geostopping Using a Recently Developed LWD Look-Ahead Ultra-Deep EM Resistivity Tool
Authors: Ma Jin , Riofrio Karol , Clegg Nigel , Sinha Supriya , Wu Hsu-Hsiang , Kotwicki Artur , Skorve Torstein , Bolstad Johansen Yngve
Published: October 2022

Geostopping is a critical operation due to wellbore-stability, well-control and HSE issues, requiring accuracy of a few meters. Reservoir boundary detection has previously been done with seismic applications and at-bit resistivity or near-bit gamma. However, seismic uncertainty can be up to 20m TVD and at-bit resistivity, and near-bit gamma requires penetrating the target. Early, accurate boundary detection, in vertical or near-vertical wells, requires technology that allows anticipation of boundaries ahead of the bit, enabling geostopping at a safe distance. A recently developed LWD ultra-deep electromagnetic (EM) tool was successfully deployed to geostop a wellbore at a target position. The system successfully predicted the top of the target formation 15m TVD ahead of the transmitter in real time, which was confirmed by gamma ray measurements. A subsequent run that drilled through the formation top confirmed the predicted top and formation resistivity. This is a game-changing technology for well construction, allowing for proactive and efficient wellbore placement.

The look-ahead, ultra-deep, EM LWD tool incorporates a deep-transmitting antenna 2.8m from the bit. To achieve a real-time look-ahead capability in near-vertical wells, anisotropic resistivity measurements are incorporated into the transmitting antenna collar, providing resistivity, anisotropy, and dip around and above the transmitter antenna while drilling. The reconstructed formation profile from the anisotropy measurement is combined with the deep measurement, enabling formation determination ahead of the bit. In a favourable condition, the integrated system can detect a formation boundary 30m or more ahead of the bit.

The EM tool was tested in challenging well conditions. The distance from the existing casing to the reservoir top was short and the tool was in a conductive formation (less than 0.6 Ω·m). This provided a very small depth interval in which to accumulate the necessary real-time EM measurements, and a relatively short depth of detection (DOD).

Despite the suboptimal conditions, the system was able to resolve the target formation top 15m TVD ahead of the EM transmitter while drilling. This was confirmed by gamma measurements after penetrating the formation, which was used as the primary technique to geostop the wellbore. The new EM look-ahead system now offers a more proactive solution to assist operators not only to geostop a wellbore at the planned position, but also to optimize the drilling parameters prior to any unexpected geological variations. This look-ahead EM technique provides more economic and efficient drilling solutions to optimize wellbore placement compared to existing techniques.

This new service makes it possible to proactively identify potential risks in vertical or low-inclination wellbores, helping to avoid drilling hazards and optimize casing shoe placement and coring operations.
Real-Time Compressional Sonic Log Prediction from Drilling and Mud Gas Data Using Machine Learning
Authors: Afifi Ruba M. , Anifowose Fatai A. , Mezghani Mokhles M.
Published: October 2022

Sonic logs are important for deriving elastic moduli of rocks, which can be useful in calculating in-situ stresses, estimating safe drilling mud weight, controlling wellbore stability, and constructing velocity models for seismic processing. Practically, determining the geomechanical information of the subsurface in real-time can alleviate operational risks and improve formation evaluation. Since sonic logs are not acquired in real-time, machine learning can be utilized to estimate them in real-time using drilling parameters and mud gas data.

This study uses Random Forest machine learning technique to predict compressional wave slowness in real-time by utilizing surface drilling parameters and mud gas data. Out of a total of five wells, the regression model is trained with data from four wells. The input parameters for each depth point include conventional drilling parameters (rate of penetration, torque, weight on bit, etc.) and mud gas data. Various preprocessing techniques were applied on the input parameters prior to model training to ensure good quality. Validation was performed on wells with existing sonic logs that were not included in the training. Model performance is measured by the correlation coefficient and the mean absolute percentage error.

Results show that predicting compressional sonic logs in real-time is feasible using machine learning. First, a model was tested to observe the effect of excluding certain depth intervals with high uncertainty in data values on model performance. The model's performance was enhanced and gave better correlation coefficient and lower mean absolute error. Therefore, cleaning data of uncertain intervals before running the model can improve sonic log prediction. Second, we investigated the effect of adding mug gas data as input features on model performance. Improvement in sonic log prediction was observed in some cases, and not in others. A sensitivity analysis was conducted on the developed models to determine the relative importance of the various input parameters on compressional sonic log prediction.

Valuable information can be extracted from sonic logs in real-time to reduce operational risks associated with drilling. This study demonstrates the effectiveness of utilizing real-time data for compressional wave slowness prediction, saving significant time and cost. Through the use of machine learning, data cleaning, and model fitting, prediction can be automated. This allows for scaling up the analysis on all the data available. We plan to apply additional preprocessing techniques, include more wells, and perform feature selection on the data to improve the prediction accuracy.
Machine Learning Look-Ahead Application for Geosteering with Uncertainty Estimation
Authors: Miotti Fabio Marco , Sreekantan Jaijith , Meunier Kara
Published: October 2022

Horizontal well placement activities aim to keep the wellbore within the hydrocarbon pay zone to maximize the production from wells. This novel data-driven solution provides well engineers with a tool for updating the petrophysical properties ahead of the bit from log measurements (offset, horizontal wells) and geophysical attributes (i.e. Amplitude Versus Offset properties). The goal is to automate the reservoir model update while drilling by exploiting the machine learning capabilities integrated in DataOps architecture.

The data-driven approach consumes well log data and geophysical attributes (AVO) to provide an updated estimation of the petrophysical properties ahead of the bit in geosteering scenarios. In the initial stage, the system represents the current state of knowledge of the reservoir as the machine learning algorithm is trained on the available static data (offset wells, geophysical attributes, seismic interpretation). While drilling, new data is assimilated by the system to increase the state of knowledge of the reservoir. The new data set is then interpreted and used to retrain the neural network to update the estimated reservoir properties.

The solution produces a continuous update of the reservoir rock properties ahead of the bit in terms of porosity, water saturation and clay. These rock properties are estimated by machine learning, and they support the decision-making of the drilling engineers as they are linked to the formations encountered by the bit while drilling.

The rock properties distribution is visually represented by a 3D spatial distribution that reflects the geometry of the reservoir. In essence, the 3D grid is the same used for defining the AVO elastic attributes such as acoustic impedance and Vp/Vs ratio. The solution also provides as outcome the confidence of the prediction (uncertainty assessment), as for each rock property the algorithm estimates a probability density function.

This machine learning solution is integrated in a DataOps architecture to enable straightforward scalability in E&P organizations to guarantee data hygiene for both input and output data and to enable overall easy access to data and metadata associated with the reservoir model. This system enables geosteering look-ahead of the bit via a machine learning application that uses well log measurements and geophysical attributes.
Delineation of Multi-Phase Wellbore and Formation Fluid Distribution in Abu Dhabi's Onshore Horizontal Wells
Authors: Kim Yonghwee , Abdel Aziz Ahmed Saber
Published: October 2022

Abu Dhabi's onshore oil fields are generally mature and contain carbonate reservoirs with light oil and gas. Various well types have been employed, such as vertical, highly deviated, and horizontal wells with cased hole or openhole completions. Surveillance of wellbore and formation fluid attributes is essential for reservoir management decisions and hydrocarbon production enhancement. This paper discusses surveillance techniques to understand multi-phase flow characteristics and reservoir saturation.

Formation saturation monitoring and production profiling have been performed actively using pulsed neutron logging (PNL) and array production logging (APL) techniques. Challenges in employing the APL method in Abu Dhabi onshore fields include (1) many wells are horizontal with barefoot completions, (2) horizontal sections extend typically more than 2000-ft long with irregular and undulating trajectories, and (3) wells contain asphaltene, debris, and other materials preventing optimal spinner flowmeter functionality. After reviewing each well condition, well environment-specific combinations of APL, nuclear production logging applications for holdups and water velocity calculations, and an advanced three-phase formation saturation analysis technique were determined. This approach overcame several challenges to deliver surveillance objectives.

We demonstrate four case examples, delineating well-based production and formation saturation profiles in various conditions. Two nuclear measurements exhibiting different sensitivities to oil and gas were combined to compute three-phase formation saturation. When a horizontal openhole wellbore was severely under-gauged, the pulsed neutron-based holdup application was used to avoid an APL tool deployment that might result in tool damage and unsatisfactory data acquisition. Additionally, for wells with good wellbore conditions, pulsed neutron-based and APL-based holdup data sets were acquired, and analysis results were compared. A stationary water velocity calculation method when water cut was high was also adopted to identify downhole water sources, and in-situ water production profiles from APL and nuclear applications were compared.

An effort to evaluate production profile and in-situ saturation effectively from highly deviated- and horizontal wellbores to improve hydrocarbon production is described. The delineation of production profiles and formation fluid distribution allowed operators to determine reservoir and production management strategies.
Halite Pore Space Plugging Evaluation Based on the Logging Data for the Cambrian Ara Group Intra-Salt Tight Carbonate Reservoirs (South Oman Salt Basin)
Authors: Smirnov Dmitrii , Hashmi Mohammed , Al Hadhrami Abdullah , AL Isaee Omar , Fanis Khayrutdinov , Agrawal Pankaj , Kumar Kamlesh , Kaabi Saqer
Published: October 2022

There has been a string of exploration discoveries in Cambrian Ara Group intra-salt carbonate reservoirs in the South Oman. Some of the reservoirs failed to produce at expected rates due to halite presence in the pore space, which is one of the highest risks for hydrocarbon exploration in this area. The objective of this study was to define novel quantitative algorithm to estimate halite volumes in the pore space.

Although halite cementation is known as a major risk for hydrocarbon production, a limited number of studies have focused on the impact of halite cementation on productivity, well integrity and ultimate recovery. The quantitative halite volume evaluation based on the logging data required an integrated approach to open hole and cased hole data collection and analysis. The open hole data included: thin section and XRD core analysis, density, neutron, sonic, resistivity, formation pressure and sigma capture-cross section. Net pay cut-off based on calculated halite volume was defined. Cased hole production logging was used to confirm net cut-off definition. The integrated logging data analysis and the developed quantitative halite volume evaluation algorithm mainly based on sigma log was successfully implemented in a few ongoing development projects. The evaluation results were successfully used for hydrocarbon volume calculations, well placement and perforation interval selection to improve production performance and reduce field development uncertainty in recoverable volumes. Understanding of consistent pattern for halite distribution allow improve exploration success. Avoiding perforation of intervals with high halite content in the pore space reduced production deferment due to surface equipment and tubing plugging by salt. Appreciation for the role of halite plugging in the reservoirs properties distribution and deterioration significantly improve history match for hydrodynamic models. The evaluation algorithm for quantitative halite volume estimation in the pore space have been developed and introduced for the first time and benefits from its implementation are expected for the upcoming exploration and development projects for the salt encased carbonate reservoirs.
Uncertainty Analysis for Seismic Salt Interpretation by Convolutional Neural Networks
Authors: Jiang Fan , Osypov Konstantin , Toms Julianna
Published: October 2022

One of the significant challenges in seismic interpretation is to accurately delineate subsurface features and quantify the uncertainty of the interpretation results due to the non-unique nature of seismic processing and imaging. Salt interpretation usually has limited resolution and relies upon an interpreter's experience with a limited set of geological concepts. In seismic interpretation, especially salt interpretation, researchers have focused on improving the accuracy of pixel predictions by developing various neural network architectures, such as Dense U-Net, Attention U-Net, Residual U-Net, etc. Studying uncertainty quantification of point predictions is important in assessing prediction quality. In this paper, we implemented Monte-Carlo dropout analysis in the variational inference setting with a Bayesian Neural network (BNN) to analyze the aleatoric and epistemic uncertainty of the salt classification. Our approach helps to analyze the posterior distribution from the variational inference and quantitively measure the range of predictive probability distribution.
Advanced 3D Seismic Studies Delineate Paleo Geomorphology and Facies Distribution at the End of the Thamama Depositional History, Dubai Offshore
Authors: Muhammad Adnan , Goddyn Xavier , Moreira Luis , D'Cruz Melroy Anthony , Freile Juan Pablo , Mehrotra Nagendra , Storey Simon Payne , Han Christopher
Published: October 2022

Exploration activities across the world's mature oil basins face increasing challenges as usually the remaining plays include subtle traps with strong stratigraphic components, situated in areas with well-established oil sources, timing and migration paths.

The advancement of seismic acquisition and processing coupled with inversion, frequency enhancement and rock modeling provides sharper images of different seismic events, ultimately related to changes in the studied rock. These resulting images, illuminated the potential trapping mechanisms and the identification of new exploration prospects when incorporated with sedimentological, tectonic and paleo-geomorphological models based on well data.

Recent exploration success and subsequent field development in the offshore Dubai study area (Figure 1) has demonstrated a highly complex setup in both structural and sedimentological terms. This new play is a fringing reef belonging to a late Thamama cycle located on the flank of one of Dubai's major fields. In this area the legacy seismic from the 90's had defined a potential field closure which has proven to be more complex under the light of the latest 2019 seismic acquisition campaign and initial development results. Regional faulting shows sealing capacity over a specific direction making additional entrapment possible and providing strong exploration potential. On the reservoir side, the rock facies clearly control the water saturation profiles; increasing the thickness of the transition zone by tens of feet towards the flank as seen in the development wells. Additionally, karsts and presence of open fractures created challenges for geosteering horizontal wells close to the reservoir roof and within a slim oil column.

This paper illustrates the seismic interpretation of this subtle and complex reefal carbonate play, incorporating advanced seismic inversion products like Ji-Fi inversion (Joint Impedance – Facies Inversion), high definition frequency blends and advanced seismic attributes, combined with geological results. It will explain how these modern technologies helped in understanding this complex field in terms of its geomorphological setup and their impacts on field development strategies.
Overburden Drilling Challenges & Their Possible Mitigations Using Integrated Seismic Structure Characterization in a Giant Carbonate Field in Middle East
Authors: Ahmad Jamal , Mohamed Naeema Ahmed , Alhammadi Sarra Husain , Almazrouei Khulood Ahmed
Published: October 2022

The ability to identify subtle structural and paleo geomorphological features within carbonates may significantly reduce wide range of drilling challenges including stuck pipe, breakouts, casing failure, lost circulation, hole collapse, washouts, etc. Current study emphasis on integrated approach to discuss drilling challenges, their possible mitigations and subsurface risk assessment.

This study is a multi-disciplinary application of integrated borehole and advanced seismic attributes to identify hazards, mainly linked with drilling problems. In this regards, paleo structure mapping is initially utilized to broadly outline areas in the field that may be associated with potential karst collapse features development. These karst collapse features are mainly responsible for dynamic mud losses and may also cause other problems (e.g., casing failure, etc.). One of the main challenges observed to confidently characterize karst collapse and other subtle features is that seismic data contains a lot of overburden noise hence an improved approach is proposed to eliminate seismic noise and enhance S/N ratio. Advanced seismic attribute volumes are then produced to capture full field lateral as well as vertical distribution of subtle features. Integrated results are calibrated with borehole image, core, logs, PLT, mud losses, Hall plot and CUM injection in vicinity. A novel approach is introduced to calculate unmonitored injection area of influence and other associated subsurface risks assessment.

An improved Integrated approach used in this paper shows promising results. Full field distribution of karst collapse features is outlined confidently and results are validated with dynamic data and diffraction seismic imaging. Vertical extent of karstified zone is clearly captured in cross sectional view, which ties with petrophysical zonation, PLT, core and dynamic mud losses. Furthermore, the novel approach of Injection area of influence calculation improves subsurface understanding and highlight other challenges e.g. pressure anomalies or future disposal wells planning, etc. Two examples are presented in this paper for reference.

An approach defined in this paper improves confidence in subsurface hazards identification, well plan optimization and minimizing unexpected costs associated with mud losses, sidetracks, etc.