bluuebunny/crossref_metadata_2025 huggingface dataset:
A New Well Selection Method Based on Improved Pressure Index for Polymer Flooding
Authors: Chen Cunliang , Han Xiaodong , Liu Xue , Wang Cheng
Published: January 2020

Polymer flooding is one of the important measures to exploit the remaining oil in the middle and high water cut of oil fields. And the key to the success of the polymer flooding is the selection of the polymer flooding well. Pressure index (PI) and the degree of fullness (FD) are significant parameters, which are commonly used for polymer flooding project design and injection well performance analysis in China, due to their economical application. However, PI and FD are insufficient in discrimination and calculation method, which can only reflect the present heterogeneity of the formation. As a result, efficiency of polymer flooding decision might be not as good as expected.

Improved pressure index (IPI) is established on basis of PI and FD. IPI is the ratio of the mean of pressure to the downfall of the wellhead pressure under the condition of unit water injection. The smaller the IPI value, the more the polymer flooding should be made. IPI not only takes the present heterogeneity of the formation into consideration, but also the transformation of pressure variation tendency. And IPI is a dimensionless parameter, which keeps initial advantages of PI and FD—simple and low cost.

This method has been applied to nearly 50 Wells. The success rate of polymer flooding exceeds 92%. The measure reduce the water cut at the same time increase oil production. It not only improves the recovery yield, but also brings good economic benefit. In addition, the paper presents a field case study to validate the methodology. IPI is far more accurate than PI and FD. In summary, IPI is not only feasible, but also saves a lot of money.

IPI has been applied to several oil fields in Bohai. And the effect is remarkable, which provides a good reference for the development of other oil fields.
Comparison Between SCAL Measurements and Pore-Scale Network Models for Neutrally Wet Sandstone on Two-Phase Oil-Water Empirical Correlations and Petrophysical Properties
Authors: Mahmud Walid Mohamed , Ermila Mansur , Aljahmi Rida-allah , Esseid Nasr-eddin
Published: January 2020

Secondary oil recovery by waterflooding is usually achieved in neutrally and water wet reservoirs. Special core analysis (SCAL) data are difficult to obtain and expensive, we therefore generate experimentally-derived petrophysical correlations based on SCAL experiments conducted on neutrally wet sandstone in order to further understand maximizing oil recovery. The key objectives of the present study are to obtain and analyze the possible relationships between the reservoir petrophysical properties that are essential for reservoir simulations. The experimentally obtained petrophysical parameters and generated relationships are compared versus the prevailing initial water saturation, absolute permeability and wettability. Experimental results are then compared with network modeling results from the literature. Network modeling is a promising tool that has many usages including the convenient estimation of capillary pressure, relative permeability and residual oil saturation that would otherwise be obtained through lengthy and expensive SCAL experiments. However, network modeling predictively has been questioned in terms of making a full priori prediction of multiphase flow properties in mixed and neutrally wet systems as true representation of pore geometry and wettability are most challenging. Scaled, two-phase oil-water system, endpoint relative permeability was found to be linearly and strongly correlated to wettability. Residual oil saturation, however, was found to be curvilinear upward correlated to Amott-Harvey wettability. Comparing the experimental results of the present study with previous network model results, limited agreement was observed. Disagreement was mainly due to pore space wettability misrepresentation in network models. The representation of neutral wettability is the path towards more realistic physical description of pore-scale multiphase flow since most reservoirs tend to show some degree of neutral wettability.
Real-Time Downhole Zonal Gas Composition Tool for Production Logging
Authors: Andrews Albert Ballard , Speck Andrew , McCowan David , Mukerji Parijat
Published: January 2020

There is currently no production logging tool that can analyze insitu gas composition in wells that intersect more than one pay zone. In high-value gas wells zonal isolation is useful for enhanced oil recovery (EOR) applications such as injection monitoring, pressure maintenance, and identification of layers that contain low-calorific-value gas. To unlock these key applications related to gas reservoir management, a new production logging tool (PLT) has been developed that introduces downhole gas composition analysis to the PLT string. The prototype has been tested in a gas storage well and a producing well. For gas field applications with pressures more than 3,000 psi, the estimated mole fraction errors in continuous logging mode are ~2% for methane and ~1% for ethane, propane, nitrogen, and carbon dioxide.
Functionalized Layered Nanomaterials: A Next-Generation Shale Inhibitor
Authors: Patel Hasmukh , Santra Ashok , Thaemlitz Carl
Published: January 2020

Detrimental formation damage can occur while drilling unconventional shales, owing to hydration and subsequent swelling of the clays. Therefore, clay stabilization is an essential component for efficient wellbore construction and treatments involving water-based reservoir fluids. Several different types of clay stabilization additives are available commercially, whereas, it is important to compare their cost, effectiveness, durability, and environmental impact while making a decision. We have developed organic-inorganic layered material (MSil-N) where the organic functionalities have been covalently linked on the surface of the inorganic nanometer-thick platelets. Analytical techniques such as powder X-ray diffraction and spectroscopy were used to characterize this novel, next-generation shale inhibitor. Clay stabilization efficacy of MSil-N is studied and compared with conventional clay inhibitors through clay swelling tests using a capillary suction timer. Pierre II shale was also used to determine swelling and hydration characteristics using the dispersion method. We have also demonstrated the formation of the coating on the surface of shales using electron microscopy. Conventional clay stabilization compounds are solely organic molecules, however, MSil-N is a hybrid of organic and inorganic components. The presence of inorganic entities in MSil-N provides excellent coating strength compared to a solely organic film on the clay, effectively shielding from the hydration of clays. Since the ionic MSil-N have inorganic moieties, it shows exceptional thermal stability unlike organic inhibitors.
Drones Make a Step Change on How the Oil Industry Manage Safety and Environmental Risks
Authors: Saadawi Hisham
Published: January 2020

Continuing development in the technologies of unmanned aerial systems or drones offer opportunities to the oil industry to make a step change to the way we manage safety and environmental risks. The use of drones can minimize exposure of personnel to dangerous environments, monitor the environment and enhance asset integrity.

The SPE vision is to advance the oil & gas community's ability to meet the world's energy demand in a safe, environmentally responsible and sustainable manner. HSE or Health, Safety, the Environment and Sustainability are core values in the oil & gas industry.

This paper reviews how the current and potential applications of drones in the oil industry can enhance safety and environmental aspects of oil and gas operations.
Experimental Study on the Wettability of Longmaxi Formation Shale in the Sichuan Basin, China
Authors: Tao Liang , Kang Ning , Deng Xianan , Hou Dianpeng , Guo Jianchun , Li Lingduo , Zhao Zhihong
Published: January 2020

The wettability of conventional reservoirs have been extensively studied in the past. However, Shale is rich in organic matter, composed of many mineral components in complex relationships, and contains pores of various scales from micrometer to nanometer, so it is very difficult to evaluate the wettability of shale. In this study, low field nuclear magnetic resonance (NMR) was used to test the water wettability of shale and a new mixed wettability model was built to quantitatively calculate the organic matter contact angle and evaluate the water wettability of organic matter. The experimental results show that the surface of the shale exhibits complex non-uniform mixed wettability, both oil-wet and water-wet; with the increase of soaking time, the water wettability of shale enhances significantly and the equilibrium time of water imbibition is 5-10 days; the average contact angle of water with organic matter is 75.2°, indicating water can enter organic matter pores, but at weaker capacity than entering inorganic pores. The research results are helpful for making clear the micro mechanism of the action between fracturing fluid and shale reservoir and designing fracturing scheme.
Enhanced Seismic Interpretation Guided by Multi-Azimuthal Borehole Seismic Data
Authors: Kumar Rajeev , Beck Byron , Al-Enazi Falah , Shabbir Ahmed
Published: January 2020

In the oil & gas industry, surface seismic imaging is critical in defining the sub-surface structure & stratigraphy but could suffer from poor seismic resolution due to complex geology. This paper describes applications of Walkaway and Walkaround VSPs recorded over an oilfield with low surface seismic resolution located in the offshore Arabian Gulf. Two further challenges needed to be addressed: i) estimation of azimuthal anisotropy, and ii) calibration of PS seismic data.

Walkaway VSP was proposed as a viable solution to obtain the higher seismic resolution by placing the receiver below the strong shallow reflectors. A multi-azimuthal (4 orthogonal lines) walkaway VSP survey was acquired based on pre-survey modeling to achieve the objectives of higher resolution and calibration of PS data obtained during OBC acquisition. Walkaround VSP was also acquired in two settings: a deep setting to estimate the azimuthal anisotropy to provide information on presence of natural fractures in the main producing reservoirs, and a shallow setting to investigate the causes of a major lost circulation zone.

3-Component downhole receivers and a powerful seismic source (6-Gun Cluster) were used to acquire good quality signal below the near surface attenuating layers. Passing through an elaborate 3-component processing chain, the walkaway survey resulted in hi-resolution subsurface PP and PS images (both in time & depth). These images provide detailed sub-surface features which were not observed in the existing surface seismic, resulting in improved reservoir characterization, as well as calibration of the surface PS seismic data. Walkaround VSP data were interpreted in terms of fracture azimuth (Fast Shear direction) and fracture density variation with depth (ratio of transverse to radial amplitudes). The Walkaround VSP results show good correlation with core data across two discrete reservoir intervals. Walkaround VSP data recorded across the shallow lost circulation zone showed strong anisotropy that coincides precisely with the lost circulation zone indicating high fracture density, with the fast velocity azimuth being consistent with the regional stress field.

It was the first time that high resolution VSP images (vertically and spatially) were generated for this field. High resolution walkaway VSP images were utilized to enhance the existing horizon and fault interpretation and reservoir characterization. The Walkaround VSP also helped to understand the azimuthal anisotropy and presence of natural fractures near the well in the main producing reservoir.
Prevention of Barite Sagging for Invert Emulsion Drilling Fluid While Drilling High-Pressure High-Temperature Wells
Authors: Basfar Salem , Elkatatny Salaheldin , Al-Majed Abdulaziz , Al Sheri Dhafer
Published: January 2020

High-pressure high-temperature (HPHT) reservoirs required special drilling fluid with high density and steady rheology to sustain the challenging conditions. Barite is one of the most weighting agents to increase the mud density at a low cost. But drilling HPHT wells causes settle the barite particle down in the wellbore known as barite sagging. Barite sagging may lead to several issues, for instance, stuck pipe, density variation, loss of circulation and well control problems.

To prevent the barite sagging, a new copolymer was used in this study. Static sag experiments were conducted to evaluate the mud in drilling break for both cases vertical and 45° inclined wells, dynamic sag tests also were performed to simulate the sagging while drilling. Static and dynamic sag tests were conducted to evaluate the ability of copolymer to suspend the weighting materials in the invert emulsion drilling fluids (IEF). Then the effect of adding copolymer in rheology, electrical stability, and HPHT filtration was achieved.

The objective of this study is to assess the effect of adding the new copolymer to IEF (polymer based on styrene and acrylic monomers) on the suspension efficiency of the weighting agent and rheological stability in HPHT condition

The results obtained showed that 1 lb/bbl of the new copolymer didn't affect the electrical stability of the invert emulsion mud. The sag issue was prevented after adding 1 lb/bbl of the copolymer for both vertical and inclined situation and in the dynamic case at a temperature greater than 300 °F. For the rheology test, the copolymer enhanced the plastic viscosity, yield point and gel strength of the mud to increase the mud stability during drilling HPHT wells. Adding 1 lb/bbl of copolymer had no effect on HPHT filtration loss and filter cake thickness.

The novelty of this study is to provide the oil and gas industry with newly designed mud to solve the barite sagging for the invert emulsion drilling fluid at high density to sustain the HPHT.
Integrated Asset Model as Decision-Making Tool to Design Surface Network and Optimal Artificial Lift System
Authors: Maiorano Stefano , Viganò Marco Cesare , Selvaggio Pietro , Rossi Roberto , Distaso Ripalta Eleonora , Stano Elena
Published: January 2020

This work describes an innovative application of Integrated Asset Model (IAM) implemented for Mexico Area-1, aiming to simulate the whole asset development. The context of application is strongly complex, since the asset is composed of five reservoirs, connected to the same Floating Production Storage and Offloading unit (FPSO). The reservoirs are separated and different in terms of structure, initial pressure regimes and characteristics of oil.

A cross-platform model of the whole Area-1, has been developed in order to implement simulation constraints from asset to well level in a unique tool.

Moreover, an innovative process was defined to increase the accuracy of the IAM, improving the control of the wells equipped with electrical submersible pumps (ESP), through the honouring of the ESP working conditions. Reservoir models include actually dedicated instructions to monitor and handle wells production according to gas-liquid ratio (GLR) at the ESP intake. This allows to operate the pumps as per design, obtaining more reliable simulation results.

The IAM, combined and enhanced with the new process, enables to run several sensitivities comparing different technologies for network configurations and artificial lift systems in order to select the finest solution to maximize the production. The enhanced model, improved in reliability, permits, in fact, to dispose of a unique tool suitable for different purposes: multi-phase pump (MPP) deployment assessment, ESP design support, water injection handling and facilities sizing.

In conclusion, the enhanced IAM merges all the constraints in a single apparatus allowing the monitoring of the asset from the reservoir to the network scale, by means of the generation of reliable fluid production profiles.
Machine Learning for Proxy Modeling of Dynamic Reservoir Systems: Deep Neural Network DNN and Recurrent Neural Network RNN Applications
Authors: Chaki Soumi , Zagayevskiy Yevgeniy , Shi Xuebei , Wong Terry , Noor Zainub
Published: January 2020

A methodology to construct deep neural network- (DNN) and recurrent neural network- (RNN) based proxy flow models is presented; these can reduce computational time of the flow simulation runs in the routine reservoir engineering workflows, such as history matching or optimization. A comparison of these two techniques shows that the DNN model generates predictions more quickly, but the RNN model provides better quality. In addition, RNN-based proxy flow models can make predictions for times after those included in the training data set. Both approaches can reduce computational time by a factor of up to 100 in comparison to the full-physics flow simulator. An example of the proxy flow model application is successfully demonstrated in an exhaustive search history matching exercise. All developments are shown on a synthesized Brugge petroleum reservoir.
Shrouded Y-Tool Application for Optimum ESP System Run Life
Authors: AlRashidi AlAnoud , AlAnsari Aminah , Radcliffe Alan
Published: January 2020

It is critical to manage the temperature rise seen in the electrical power system and submersible motor, in order to have an optimum Electrical Submersible Pump (ESP) run life. This paper presents a case study in which a solution was applied to better manage the heat rise seen in the ESP during operations, particularly in low flow applications, that has led to a measurable increase in ESP run life across the field.

A Middle Eastern Operator of ESPs had installed wells completed with Y-tools and ESPs that showed unusually high motor temperatures and shorter than expected system run lives. A study was conducted, and the remedial action implemented was to install a shroud around the Y-tool, reducing the flow space in the annulus thus increasing the velocity of fluid past the motor. The study compared the data gathered from the shrouded and non- shrouded Y-tool ESP installations to determine the effectiveness of the corrective actions.

Motor temperature is a function of bottom hole temperature, percentage load against nameplate, fluid properties, power quality and fluid velocity past the ESP motor. This study has shown that the shrouded ESP significantly increased the fluid bypass velocity (more than 1ft/sec) alongside the submersible motor to deliver the required cooling for stable, reliable operation. Unshrouded systems experienced higher motor and intake temperatures that is instrumental in the deterioration in the insulative properties of the electrical system and leads to greater current leakage with the passage of time.

This paper will provide full, detailed knowledge on shrouded Y-Tool systems that can be effectively applied for low flow rate production, allowing well bore full access for wireline or coil tubing jobs. Moreover, efficient motor cooling is provided by the higher fluid velocity and while providing a better pump performance, is expected to result positively in ESP run life.
Continuous Circulation Drilling, MPD: Adding Value Through Safety Enhancements and Cost Control.
Authors: Colaianni Francesco
Published: January 2020

In an industry climate with a high focus on reduced well costs and drilling time, the use of continuous circulation system (CCS) as a simple MPD solution offers many benefits, including the control of bottom hole pressure along with enhanced wellbore cleaning and stability. These features become crucial requirements for personnel safety, operational efficiency and cost reduction, particularly in drilling environments with very narrow margins and more extreme deep-water, high-pressure/high-temperature situations, high deviated and extended reach horizontal sections.

Continuous circulation drilling naturally provides a downhole steady-state condition and, as a result, the formations do not suffer from pressure oscillations while hole-cleaning and borehole stability improve, reducing the chance of drilling issues related to bottom hole pressure management in open hole. The CCS can be applied as a stand-alone device or in combination with a closed-loop MPD System, making connections with MPD simpler and faster.
Technology of Multi-Stage Hydraulic Fracturing Dual Laterals in One Trip for Multilateral Wells
Authors: Zhang lina , Chen Shichun , Zhang Heng , Zhang Songjie , Yang Wenling , Hu Jintong , Yu Xueliang , Cui Yuanzhong
Published: January 2020

With its advantages of a shorter construction period, a less cost and a higher production, multilateral drillingtechnology has become widespreadthroughout the petroleum industry. Multi-stage hydraulic fracturing technology is also widely used in the field to deal with poor reservoir conditions such as layers with low pressure and permeability. However, conventional hydraulic fracturing technology used in multilateral well encounters difficulties. Not only has itcalled for a complicated operation of accurate re-entry, but also significantly extends the completion time while having to controlthe well, thus greatly increasing the risk of making a dead well and limiting the development of the technology.

In order to deal with those difficulties, the authors of this study researched this new technology which can achieve the goal of self-orientating control, accurate re-entry control and fracturing multilaterals without having to controlthe well. The first aim is to achieve the goal of a single trip self-orientating control system during drilling different multilaterals, thus means drilling tools will enter the lateral we choose only by the self-orientating control system while without any other tools or instruments in this process. To get this, a self-orientating system is studied which provides a base for subsequent operations and it is kept at the bottom of the hole perpetually. In other words, the self-orientating control system functions as the root of the whole system. The other aim is to achieve the goal of selective re-entry. During the processes of washing and fracturing, the BHA must re-entry the lateral designed, thus a special tool is needed to work as a guide to lead the BHA into the right hole. The special tool we designed is called junction. It works as a bridge between the bottom lateral hole and the running BHA. The re-entry system will enter the hole selectively based on the mechanical parts onthe junction. The last but the most important is to fracture the multilaterals together without having to controlthe well. Compared with conventional operation, fracturing/killing/bridging operationsare not needed for the lower lateral before starting to drill the upper lateral, thus not only one trip has been decreased, but also no risk to lead to a dead hole.

A Fieldtest has been performed on an abandoned well, showing the success of the technology. Special tools and operation procedures were involved. The two laterals were fractured only in one trip which demonstrates its superior performance compared to conventional multi-stage hydraulic fracturing that requires two or more trips for multilateral wells.
Air/Foam Drilling Coupled with Drilling with Casing Technique Enables Operator to Drill and Isolate Troublesome Section to Target Depth on Multiple Wells in Pakistan
Authors: Khalid Ali , Ashraf Qasim , Luqman Khurram , Hadj-Moussa Ayub , Khurshid Imran
Published: January 2020

The Kirthar fold belt located in southern Pakistan, contains some of the largest gas reserves of the country. Operators when attempting to drill in the locality face a major hurdle in the surface hole sections. The surface section on most wells contain a group of three formations, Kirthar Limestone, Ghazij Shale, and Laki Limestone. Both the Limestone formations are highly fractured and exhibit total circulation losses, while the Shale formation is highly reactive and exhibits a swelling and sloughing behavior when drilled with a conventional water-based mud system. The operator on many occasions suffered stuck pipe incidents up to 3 times per well due to the massive circulation losses and shale instability problems.

An air/foam system was initially used to eliminate the major problem of total lost circulation. The foam base fluid was formulated to contain a special blend of shale inhibitors to address the reactive nature of the shale formation. A special combination of polymers was also added to the base fluid to stabilize the foam in the presence of these shale inhibitors. The designed air/foam system was able to eliminate lost circulation completely and minimize the swelling and sloughing of the shale formation in a few wells drilled. While running the surface casing the operator observed high compression against the shale formation and in most instances the casing was set prematurely leaving a part of the vulnerable limestone formation exposed in the next section. As the next section required a much higher mud weight to drill, numerous cement plugs had to be peformed to bridge off the exposed limestone formation.

The operator then further desired a solution that would enable them to drill without losses and allow them to land the surface casing to target depth. A drilling with casing system was first considered for this objective, but it was found to be incompatible with the air/foam system. The operator then finally decided to drill the section with an air/foam system and run the casing with a drilling with casing system, reaming through the troublesome shale formation.

A series of wells were then drilled with an air/foam system, and the casing was run with a special drillshoe laced with pdc cutters. As expected high compression was observed against the shale formation. The casing was then connected to the top drive utilizing a specifically designed tool and reamed joint by joint to bottom. A conventional mud system was used while reaming the casing to bottom. The operator by the application of these two unique methods was able to drill and isolate the section in all future wells to target depth and achieve a cost and time saving of as much as 50 percent.
Customized Integrated Approach for Increasing Reservoir Understanding and Lowering Costs: Case Study, Deepwater Gulf of Mexico
Authors: Michel Franck , Rennie Allan , Guidry Garrett C. , Robbins Ben , Iqbal Shaikh Aamir , Kizziar Steven
Published: January 2020

In the deepwater Gulf of Mexico (GOM), an operating company planned to drill and log a challenging wellbore in a mature field within the Upper Tertiary set of target sands. High levels of depletion as well as extremely tight pore pressure margins were anticipated. The operator and the service company's drilling and evaluation (D&E) integrated teams developed a highly collaborative environment from the early planning stage of the project, aligning people and processes and enabling applications.

Regional knowledge from an archived geomechanical model was updated during collaborative planning sessions, enabling both parties to have a consistent understanding of the subsurface challenges to correctly drill and log each interval. Potential wellbore instability issues were mitigated using a proactive geomechanics analysis and hydraulics management from an integrated real-time operations center (iROC).

Formation compressional slowness from a logging-while-drilling (LWD) sonic system was used, updating the geomechanical model for accurate real-time pore pressure and wellbore stability analysis. Additionally, the sonic system was used for top-of-cement (TOC) evaluation behind the intermediate casing to satisfy the Bureau of Safety and Environmental Enforcement (BSEE) requirements to differentiate fully bonded pipe from free pipe. Geosteering services from real-time log response correlations and at-bit geological predictions were used to correctly geostop for an intermediate casing point before pressure regression. An LWD formation pressure system provided pressure tests over various depth intervals, providing excellent fluid gradient determination for the primary target sand package. An LWD azimuthal density system delivered high-quality borehole images within the 16 ½-in. borehole section, providing dip information for geological correlation to seismic. Further, the azimuthal density image system resolved the interbedded shale/sand sequences, allowing dip analysis for geological model correlation within the reservoir.

Challenges for this wellbore included shallow water hazards, wellbore instability, setting intermediate casing above the sand targets, and the depleted reservoir section. The deployment of specific technologies with associated unique applications discussed in detail within this paper led to superior well construction execution under time (8 days) and under budget (USD 4 million).
New Conical Diamond Element Bit Technology Coupled with FEA-Based Modeling for Bit Selection Demonstrates High Durability and Improved ROP in Compact Carbonate Formation in Deep Water
Authors: Muhammad Shafiq Shahrul Amar , Syed Muhamad Siddik , Sylvia Fayez , Ole Gjertsen , Nurul Ain Mohd Yakob
Published: January 2020

Developing reserves offshore East Malaysia, especially in deep water, often requires the operator to drill -through formations that consists of compact carbonate with high unconfined compressive strength (UCS). Efficiently penetrating these carbonate formations with conventional PDC bits has been challenging; typically, when a bit encounters this formation, a high vibration level is induced that leads to impact cutter damage, forcing a round trip for a new bit and causing nonproductive time (NPT) and additional cost for a new bit. Consequently, the cost impact is more severe to the operator, especially in deep water environments.

Traditionally, an operator has used four- and five-bladed PDC bits to drill this formation because this configuration had set a benchmark in this field compared with roller cone bits. However, a recent engineering analysis on a recently drilled offset well showed that a minimum of two PDC bits are required to reach the section total depth (TD). On the first run, the bit was pulled out of hole (POOH) due to slow ROP 6.2 m/h) and received a poor dull grade (6-7-HC-ROP). Although the second PDC bit produced slightly higher ROP compared with the first bit, it was POOH with broken cutters.

A research initiative was launched to investigate new types of cutting elements. The project was successful and yielded an innovative conical-shaped polycrystalline diamond element (CDE). This element has twice the diamond thickness of conventional PDC cutters, resulting in higher impact strength and more resistance toward abrasive wear by approximately 25%. A new bit type was designed with the CDEs strategically placed across the bit face from gauge to the bit center utilizing FEA-based modeling system. The placement of CDEs is mainly to support and protect the conventional PDC cutters from impact damage and to strengthen the overall cutting structure.

The 8½-in CDE bit was run and drilled the entire 8½-in hole section through the hard carbonate formation to TD at a significantly higher ROP compared with the offset well. Although the CDE bit was POOH due to downhole tool failure and graded 1-2-BT-DTF, the same bit was rerun and successfully completed the hole section in good condition and dull graded as 1-3-BT-TD. Compared with the offset well that required two conventional PDCs to reach TD, the CDE bit delivered more drilled interval at a higher ROP while providing a smooth, high-quality wellbore, enabling casing to be set on the first attempt. Also, the dynamic response predicted by the modeling system matched the bit, BHA, and drill string vibration profile recorded during the actual field run. Improvement in drilling performance for this run has saved the operator 15 hours for the same drilling interval.
An Innovative Solution Enabled a Client to Drill Over 70 Horizontal Wells in a Very High Collision Risk Environment
Authors: Noor Marghub Nabi , Al Muqarshi Moosa Masoud , Ovezov Murad , Delavari Kamran , Heidari Mohammad Reza
Published: January 2020

A client in South Oman was struggling to place additional wells to maintain the production levels in a Semi Steam Assisted Gravity Drainage (SAGD) project due to very high collision risks. Real Time High-Definition Surveys (HDS) application was used in conjunction with In-Field Referencing (IFR) to reduce the size of Ellipse of Uncertainties (EOU) and increasing the Separation Factor (SF) while drilling.

In a SAGD project, the placement of well either Horizontal Producer (HP) or Horizontal Injector (HI) is very critical and any deviation can cost dearly in terms of production rate. A post run survey enhancement will most likely is not going to produce the desired results and can lead to costly plug well situation. A special real time survey enhancement procedure with the help of an exclusive application was used to increase the survey density. This application provided high density industry standard MWD surveys, by using advanced algorithms with continuous azimuth & inclination data from MWD tool.

This combination benefited the client in multiple ways and most significantly, additional 70 horizontal producer & injector wells are drilled in last 4 years, which otherwise were not possible to drill. These additional wells resulted in over five million barrels of produced oil per year for the client, which translates into 204 million USD annual revenue. Additionally, it helped achieve the objective of placing the well at optimum spot to minimize the water break through and reduce the produce water. Also, the reduction in tortuosity by removing additional turns for collision avoidance resulted in longer well life and better production rates. In addition to that, managed to plan another 50 well trajectories with the help of this new technique to be drilled in near future. The well drilled with this approach has up to 30% smaller EOU size and will help the project in future with more room to place additional wells.

This survey enhancement application can benefit similar projects worldwide in a variety of ways. On one hand this will help operators to optimize the production by drilling additional wells in very congested areas, and on the other hand this will also help the Sub-Surface Team (SST) to calibrate their existing geological model with more accurate reservoir boundaries.
Evaluation of Lateral BHA Twist-Off Incidents and the Effect of a Redesigned Thread Connection on Reducing Twist-Off Risk in the Permian Basin, USA
Authors: Chen Zhenyu , Simon Aaron , Shen Yuelin , Chen Wei , Zhang Zhengxin , Shahid Tanveer , Liu Guoyu
Published: January 2020

A common issue encountered when drilling in the Permian Basin involves the twist-off of a bottomhole assembly (BHA) component. A twist-off incident can result in significant costs incurred due to nonproductive time (NPT) as well as lost-in-hole (LIH) charges if retrieval of the fish is unsuccessful. The paper will present several case studies to illustrate the primary cause of the failures. An innovative thread connection for BHA components was designed in 2016 to reduce risk of twist-off. The paper will demonstrate its effect on reducing twist-off risk as well as the enablement of improved drilling performance in 2019.

The paper will illustrate statistical analysis of data gathered from 2016 through 2019 comparing the performance of the conventional thread connection versus the new thread design. The goal of the analysis is to evaluate whether the thread design is effective in reducing the frequency of twist-off incidents. The bending moment of each connection within the BHA will be analyzed using modeling software to understand the stress-loading profile. Memory data from the rotary steerable system (RSS), including near-bit attitude measurements and downhole drilling dynamics, will be analyzed in conjunction with data acquired from the rig's surface sensors to identify if any abnormal drilling events are observed prior to the twist off.

The BHA bending moment study concludes that connections between the measurements-while-drilling (MWD) tool and the RSS suffer higher stress loading compared to other connections in the BHA. Empirically, field statistics confirm that the connections between RSS and MWD exhibit the highest frequency of twist-off incidents. However, further analysis is required to understand the root cause of the connection failure. The memory data retrieved from the RSS enables the visualization of hole curvature and vibration at the time of the incident. Investigation into several field cases concluded that, immediately prior to connection twist off, there is sudden change in borehole curvature and/or emergence of shock and vibration (S&V) which can dramatically reduce the expected fatigue life of the connection. Based on the statistical analysis, it can be concluded that the new connection design is effective in reducing the twist-off failure rate of the BHA. Consequently, the implementation of the new thread design enabled a step-change in drilling performance through use of a more powerful positive displacement motor (PDM) to drive the RSS system.
Energy Query Language - An Oil and Gas Domain Query Language for Big Data Analytics in Real-Time Data Streaming
Authors: Djamaluddin Basirudin , Philip Shan , Alrebh Abdullah , Iqbal Arif
Published: January 2020

Within the Oil and Gas industry, real-time data streaming is essential to conduct high-impact analytics. The Energistics Transfer Protocol (ETP) enables data to be streamed with low latency. The current mechanism of querying the data transferred through ETP is cumbersome, especially for the domain user who wants to realize the full benefits of this protocol.

Energy Query Language (EQL) is a domain-specific language (DSL) for querying data which is streamed through ETP with a concise SQL-like structure in real-time. The EQL System (EQLS) provides the ability to query streaming data in real-time across various platforms and business applications, as well as in web or analytics platforms like Python. The EQL grammar is simple enough to reduce the complexity of the current mechanism used for querying and aggregating real-time data. Built with components that can support advanced analytics requirements including big data analytics, EQLS is future-proof.
Historical Performance Analysis and Upcoming Development of Rotating Control Devices in the Kingdom of Saudi Arabia
Authors: Sehsah Ossama , Iturrios Carlos , Mahmood Azfar , Kadadha Abdallah
Published: January 2020

Drilling companies are constantly evaluating ways to improve the efficiency and safety of their operations, the way the returns of the well are circulated while drilling has remained unchanged for decades, however, having a circulating system open to the atmosphere imposes a risk to the drilling crew in the rig flow.

Conventional influx detection methods can easily allow the gasification of the mud column in the annulus before it is noticeable and H2S or flammable gas alarm can be triggered before any action is taken.

A rotating control device (RCD) is a piece of equipment that diverts the returns of the well from the rig floor while allowing the drill pipe to be rotated and reciprocated, that means tripping and drilling operations can be performed while the well is isolated from the rig floor by the RCD.

The RCD is a key component in Managed Pressure Drilling (MPD) operations as it is responsible for containing the annular surface pressure and preserving the integrity of the circulation system, hence maintaining a slight overbalance condition on the well, additionally the RCD can be deployed independently for other applications that enhance the safety and optimize the costs of the drilling operation. For this reason, efforts are made to ensure that optimum operating conditions are present to reduce the chances of system failure. Historical data detailing the performance of RCD systems, including total stripped footage, total rotating hours and failure mechanisms were used to evaluate the reliability of this technology and to set operating limits to optimize its performance.

Historically there are conditions that are known to reduce the life span of RCD bearing assemblies, such as misalignment of the Blowout Preventer (BOP) stack, hard banding or bad condition of drill pipe tool joints, excessive drill pipe vibration, temperature and type of fluid out of the well, among others. Ensuring that the operating limits are observed regarding rotating speed, pressure and temperature were observed to be key to maximizing the life cycle. It was observed that the base technology over which RCDs are designed is far from recent and new additions to the current setup are needed to "smarten up" an otherwise very basic piece of equipment, this with the intention of obtain better data regarding its operating conditions and the parameters that affect its performance. New technologies in terms of elastomer compounds, seal design improvements, monitoring systems and implementation of artificial intelligence are some of the upcoming developments discussed in this document and that are to be implemented in the short and medium term in RCD operations in Kingdom of Saudi Arabia.
Application Example: 5-7/8 Inch Openhole Whipstock Sidetrack Set at Longest Horizontal Distance From Casing Shoe in the Middle East
Authors: Baichev Stanislav
Published: January 2020

An unconventional tight gas well was drilled to a 1,973 feet lateral in hard abrasive sandstone. The drill string became mechanically stuck due to wellbore geometry. A deep, openhole whipstock was set in the 5-7/8 inch lateral section to reduce recovery time from the pipe sticking event and avoid re-drilling the section length. All recent open-hole whipstock pFrom lacements could only achieve a maximum of 300 ft distance from previous 7-inch shoe due to Weight On Bit (WOB) limitations. This necessitates drilling the horizontal footage again, especially costly in cases of a deep stuck point. An openhole hydraulic set whipstock without packer was set at the longest horizontal distance of 639 feet from the 7 inch shoe, and saved redrilling that section length. A risk assessment concluded there was minimal hole washout based on the caliper. The whipstock service company provided a detailed plan with three potential whipstock setting depths ranging from 150 up to 669 feet away from 7 inch shoe. The plan execution involved conducting a successful blind back off, making a dummy run, and evaluation of hole condition based on hole drag and maximum WOB limitation after passing each potential setting depth interval. This detailed and closely monitored approach to setting point selection ensured a record achievement of 639 feet out-of-shoe setting depth in the Middle East. The wellbore was able to be assessed for WOB required to traverse the open hole and setting point locations, absence of a wellbore anomaly present that would preclude passing the whipstock, and integrity of the running and milling assembly. This avoided redrilling 639 feet of lateral section, and saved 14 days of rig time in comparison to using a cased-hole whipstock with casing milling. An openhole whipstock utilizing a hydraulically set Latch Anchor with Extended Reach Slips enabled deep setting of the whipstock at the longest horizontal distance from casing shoe.
Real-Time Gas Leak Detection and Quantification using Smart Cement
Authors: Vipulanandan Cumaraswamy , Aldughather Ahmed , Panda Guru , Wong George
Published: January 2020

In this study, the highly sensing chemo-thermo-piezoresistive smart cement behavior as a function of temperature and pressure with a water-to-cement ratio of 0.38 was investigated. Series of quality control, curing, compression and high-pressure high-temperature (HPHT) lab experiments were performed to evaluate the smart cement behavior with pressure and temperature variations. Vipulanandan p-q curing model was used to predict the changes in resistivity with curing time. The piezoresistivity strain of smart cement after 1 day of curing under 140 °F was 207% which is much higher than the regular cement failure strain of 0.2%. The Vipulanandan p-q piezoresistivity model also predicted the experimental results successfully. Observed fluid loss and gas leak after 30 minutes of testing was recorded. The measured fluid loss was predicted using the Vipulanandan fluid loss model and compared to the API static fluid loss model. Smart cement detected and sensed gas leak throughout the fluid loss test. During the gas leak through the piezoresistive smart cement slurry, the resistivity change was positive which could be used as an indicator for immediate gas migration. During the gas leak in the smart cement slurry, the resistivity increase was about 36% at pressure gradient of 1,800 psi/ft for 70 °F curing. Vipulanandan fluid flow model, generalized Darcy's Law, predicted the non-linear responses of gas leak velocity (discharge per unit area) to the applied pressure gradient. Additionally, the electrical resistivity changes predicted the gas leak velocity in the smart cement at different curing temperatures.
Integrated Geochemical Modelling of Low Salinity Waterflooding for Enhanced Oil Recovery in Carbonate Reservoir
Authors: Elakneswaran Yogarajah , Takeya Miku , Ubaidah Amir , Shimokawara Mai , Okano Hirofumi , Nawa Toyoharu
Published: January 2020

Several mechanisms have been proposed for enhanced oil recovery (EOR) in low salinity waterflooding (LSWF). Coupling of the significant processes affecting crude oil-brine-rock system is necessary to understand the LSWF effect. In this study, mineral thermodynamic equilibrium and surface complexation reactions at crude oil/brine and calcite/brine interfaces were coupled with solute transport to simulate LSWF in carbonate reservoir. The dissolution and precipitation of minerals were considered thorough thermodynamic phase-equilibrium model, and the triple-layer surface complexation model was developed to predict the interface reactions and the associated surface and zeta potentials. These models were coupled with solute transport model to predict ionic profiles and oil recovery during LSWF. In the integrated geochemical model, the crude oil was considered as colloids and the ionic adsorbed/ionized and un-ionized surface groups of oil were transported via advective and dispersive transport. These sub-models were coupled in a geochemical code PHREEQC. The coupled model was first used to predict Ca2+ and Mg2+ profiles in chalk saturated with NaCl without crude oil. The agreement between published experimental data and simulation results validate the proposed model. A nearly equal equilibrium constant in the surface complexation model provides a similar breakthrough composition for Ca2+ and Mg2+ ions. The model was further validated in chalk core aged with the crude oil. Both model and experimental results show an earlier breakthrough composition of sulphate in oil-aged core. The model was then used to predict ionic profiles and oil recovery in two-phase flow experiment. The modelling results reproduces the experimental data on relative concentration of ionic species and pH increase with dilution of injecting water, however additional mechanism should be incorporated in the model for better prediction of oil recovery.