bluuebunny/crossref_metadata_2025 huggingface dataset:
Successful Drilling and Completion of a Short Radius Deep Gas Re-Entry Well Towards the Minimum Stress Direction
Authors: Almusallam Ali , Yahya Hany , Ab Hamid Abdul Halim , BinAli Ali
Published: November 2019

Since the foundation of the oil industry, many wells were drilled with an old design. Such wells had been limiting the reserve recovery potential. In extreme cases, some of these wells had been suspended and remedial work is now required to unlock the wells’ potential. This paper presents a case study for restoring production and increasing the salvage value of suspended wells in areas with proven production potential yet declining production yields.

Challenges for drilling the well were found in three key areas: Sidetrack Points: The main concern in this well was the failed cement job in the 9-5/8 in. casing and the pressurized formation above the targeted reservoir that had the potential to create new fluid paths through cement channels. The pressurized formation required a very heavy mud weight of 152 pcf and managed pressure drilling (MPD) to drill the previous well and incurred losses at the same time. By increasing the depth of the sidetrack point and drilling a short radius 5-7/8 in. wellbore in less than 200 ft., the risk of the pressurized formation communicating to the new lateral was eliminated. This saved the cost of drilling two hole sizes and the cost of milling approximately 1,500 ft. of existing 7 in. liner and running a new one as illustrated in Fig-1.Geomechanical Challenge and Petrophysical Demands: Due to fracturing needs, drilling toward a minimum stress direction was required even though this was not preferable from a drilling standpoint. The stuck pipe tendency becomes greater when compared with drilling toward the maximum stress direction in deep wells. Placing the well in high porosity zones required real-time geosteering using high-end logging while drilling (LWD) services in high dogleg environments. By using LWD technology with high bend rates, the required reservoir contact was achieved by drilling less footage than planned. Modified best practices played a major role in achieving these objectives.Running the Liner through the High DLS (Dogleg Severity) Environment: Drilling the short radius resulted in an averaged DLS of 30 deg/100 ft where it also reached a maximum 53 deg/100 ft across some intervals. Due to a high build rate and the azimuthal change required to reach the target. The use of oil base mud and bridging materials along with constant monitoring of mud rheology allowed the liner to be deployed successfully through high DLS section. The plan for centralizers was also modified to reduce liner stiffness while still obtaining isolation from the water bearing reservoir above the target.

The success in delivering the well and returning it to production after a challenging workover job opens the door for future activity. Restoring wells by employing the short radius drilling technique provides a cost effective solution compared to conventional workover methods in many cases.
Implementing a Successful Risk Based Inspection Program
Authors: Ali Asad , Sabry Houssam
Published: November 2019

Production of Oil, Gas and Petrochemical from production units is becoming very competitive every day. As products are sold in open market, production cost drives an organization's profitability. To keep a plant available for production as much as possible, Asset Performance Management (APM) or Asset Integrity Management (AIM)is the key. Risk based inspection (RBI) is a decision making tool that deals with integrity management of static equipment and piping through focus on prioritizing inspection based on the risk.

Review of published guidelines for RBI such as API RP 580/581, ASME PCC3, DNV-RP-G101, EN 16991 etc., suggests that they provide either oversimplified or complex explanations which makes it difficult for beginners to grasp all the aspects that are critical for a successful RBI project. Therefore, this paper is aimed to provide and discuss the essential elements for effective RBI implementation project in a simplified way. RBI project can be divided into four major phases i.e project initiation and pre-requisites, workshops & trainings, RBI analysis phase and post RBI actions. Each of these stages is discussed with details in this paper.

An overview of successful RBI program used within the industry and from the ADNOC LNG RBI implementation experience, is provided with details. Project management approach for RBI program implementation is conveyed by dividing project into different phases and highlighting the inputs/outputs and activities for each phase. Objectives, time and resources such as data and personnel required, software features that are essential, project planning and monitoring are provided.

RBI program implemented efficiently in accordance with suggested plan, results in an overall optimization of inspection for static equipment/piping while maintaining their integrity as part of a broader APM or AIM strategy.
Ranking Shale Performance from Water Flowback Analysis, Field Case
Authors: Ibrahim Ahmed Farid , Assem Ahmed , Ibrahim Mazher , Pieprzica Chester
Published: November 2019

In recent years, in unconventional reservoirs, main fracture parameters including fracture permeability and fracture volume can be early evaluated using flowback data analysis. For analysis purposes, diagnostic plots, straight-line methods, and simulation model history-matching techniques are utilized. Usually, immediate gas and water production occur during flowback in shale gas wells.

In this paper, solution of water diffusivity equation for different flow regimes during the early time of well life was used to analyze water performance. These flow regimes were determined based on the diagnostic plot of water rate vs. time. The analysis from Water RTA was used to calculate initial water in place (OWIP) and fracture parameters. The difference between the OWIP and the injected fracturing fluid was correlated against the formation water saturation.

The main conclusions from this analysis are; 1) High quality shale if the OWIP equal to the total injected water volume, and water-production data usually do not show the transient period and in some cases, boundary dominated flow (BDF) is present. 2) Low quality shale if the OWIP is greater than the total injected fracture fluid volume, and transient flow regimes are expected. High quality shale is good candidate for soaking process. The well performance increases after soaking process in the case of low formation water comparing to the high-water saturation wells.

Honoring the flowback data can help to estimate the fracture geometry and indicate the quality of the shale formation.
Intelligent Digital Oilfield Implementation: Production Optimization Using North Kuwait Integrated Digital Oil Field NK KwIDF
Authors: Al-Subaiei Dalal , Al-Hamer Mohammad , Al-Zaidan Ahmed , Chetri Hom , Sami Nawaz Mohammad
Published: November 2019

Global oil demand has led to the development of new smarter drilling, completion, reservoir management technique and technology to optimize reservoirs production. The production of Kuwait Oil Company (KOC) has reached 3 MMBOPD and KOC’s 2030 vision is to boost the production to 4 MMBOPD. In order to achieve this vision, KOC has started several technical projects and development plans. One of these projects is the North Kuwait Integrated Digital Oil Field (NK-KwIDF) a full-fledged Field project implemented in KOC.

This Paper will discuss the scale, complexity, technology used, and advantage of using the NK-KwIDF. The North Kuwait (NK) asset has five fields, around twelve hundred active wells, and seven Gathering Centers (GCs). A complex network of pipeline, trunk line, and manifold are used to connect these twelve hundred wells to GCs. In order to optimize the production from NK every barrel of production opportunity has to be considered by optimizing suitable wells and minimizing downtime from each field, resulting the development of an extensive surface network model. The extensive surface network model takes into consideration of each and every details of field e.g. pipelines, manifolds, details of GCs and wells. For each and every well in NK assets a well model is prepared considering all PVT parameters, completions, and surface co-ordinate and finally connected to surface network model with all piping information.

Once the extensive surface model was prepared, several integrated workflows were developed in order to efficiently run the surface model and analyze the output from the run. Some of these workflows are ESP Optimization and ESP Analysis workflows, which have capability to identify the Oil Gain Opportunities and diagnose ESP performance. The identify opportunities are logged into ticketing system, which monitors the life cycle of the opportunity right from the identification till implementation into the field for Oil Gains.

The full-fledged development of NK-KwIDF took almost 3 years from the day it was started, as a pilot project with 133 wells. When an excellent result in terms of production optimization and downtime minimization was recorded from the pilot project, the pilot project was expanded to full-fledged field project. The NK-KwIDF project gave an outstanding result of Oil gain from well level as well as Network level optimization. It established an excellent reputation in the oil industry where it was a source of attraction for many NOC’s and IOC’s to visit and follow the flag ship for their development and implementation of digital field technology.
Case for Vertical Hydrocarbon Migration: Case Studies, Southeast Asia Tertiary Basins
Authors: Christopher Geovani
Published: November 2019

Complex hydrocarbon distributions where reservoirs are filled by oil and gas phases with different densities and genetic types interfingering within a basin are a common phenomenon in Southeast Asia and are often attributed to vertical migration. Attempts to understanding the controlling factors of vertical hydrocarbon migration by modeling the hydrocarbon charging and entrapment history from two Cenozoic basins in Southeast Asia—West Java and the Madura Platform—are discussed.

A modified invasion percolation algorithm was used to simulate the secondary migration models, which follows the principle that migration occurs in a state of capillary equilibrium in a flow regime dominated by buoyancy and capillary forces. Three-dimensional (3D) seismic data were used as the base grid for migration simulation to capture the effect of both structure and facies variations on fluid flow.

Two models, one from the West Java Basin (fault-bounded structure) and the East Java Basin (nonfault-bounded structure), are presented. For both cases, interfingering between oil and gas occurred, with most oils trapped within the lower formations, a mixture of oil and gas dominates the middle formations, and mostly gas in the upper formation. These vertical arrangements are possible because of the relatively weak formational seals within the basin. For vertically distributed reservoirs, oil is often trapped within the lower interval, and gas is trapped at the upper interval. For a basin dominated by a vertical migration regime, the potential risk for hydrocarbon lateral travel far away from the kitchen is high, thus increasing the potential risk of prospectivity away from the kitchen. Understanding factors that help control vertical migration also help geologists better understand hydrocarbon distributions within the basins.

Case studies during which modeling helped determine the factors that influenced vertical hydrocarbon migration and the resulting potential phase distribution prospectivity risks in the studied basins are discussed.
Investigating the Chronic High Temperature Reading on the Lube Oil System of Water Injection Pumps
Authors: Alshaghab Hussain
Published: November 2019

Background: Almost all water injection pumps in our area are experiencing high temperature reading on lube oil feeding line to the bearings of disposal water injection pumps and motors especially during the summer season where it reaches 71.11 °C ESD Trip Point. The objective was to determine the root cause of this chronic problem and resolve the issue in order to avoid equipment trips as well as increasing the equipment availability. Method: Two methods were being conducted which are observing the lube oil temperature of leaving all bearings and analyze the lube temperature of each bearing outlet individually. The other method is by comparing temperatures measurements that were collected in the locations right after the (Temperature Control Valve) TCV and 1 meter away from the TCV every hour during the day time during summer season. Result: Statistics reveals that the temperature of the oil coming to the bearing is much less than 68.33 °C since some of the oil temperatures reading of oil leaving the bearings are less than 68.33 °C. Likewise, comparing temperatures measurements that were collected right after the TCV to reading collected 1 meter away from the TCV show approximately 10 °C difference in reading whereas the collected reading 1 meter away from the TCV is lower. Conclusion: the temperature sensors (one for the Hi switch, one for the Hi-Hi ESD switch and one for the TCV) are currently installed right after the (TCV). In this location, the liquid is still hot and heat transfer process between both hot and cold liquids is at the beginning phase and not completed yet. Therefore, above temperature sensors will always read the temperature of the hot lube oil especially during summer season from (11:00 a.m. to 3:00 p.m.), Hi-Hi Temperature ESD switch will be activated to trip the pump. This investigation concludes that the temperature sensors shall be re-relocated from the current location to downstream in order to provide time for the hot and cold liquids mix together. Benefits: The equipment availability will be increased as the unnecessary trips and unplanned downtime of the equipment are being avoided. Hence, it increases equipment MTBF. It also reduces number of warning alarms in control room which makes operators to focus in other issues. And most importantly that the reducing maintenance time and cost (approximately, USD 10,000 cost and five days’ work were avoided per each equipment). Example work that has been avoided to resolve the high temperature issue includes checking instrumentation healthiness, cleaning heat exchanger internally and externally, checking the fin-fan conditions, inpecting and testing TCV functionality, and inpecting lube oil tank as well as the piping which incudes the whole system.
Petrophysical Evaluation of Shale Gas Reservoirs: A Field Case Study of Marcellus Shale
Authors: Yildirim Levent Taylan , Wang John Yilin , Elsworth Derek
Published: November 2019

Successful petrophysical evaluation and stimulation treatments with horizontal drilling and hydraulic fracturing enable the economic development of shale gas reservoirs. Detailed evaluation of shale gas reservoirs before and after stimulation treatments is a prerequisite to increase efficiency and effectiveness of shale gas development. Determination of organic maturity, porosity and original gas in place remains a challenge using traditional petrophysical models due to the complex pore networks and ultra-low permeability of shale. On the basis of a petrophysical model for shale gas reservoirs (Passey et al., 2010), we propose an integrated approach for petrophysical evaluation using analyses of lithology, porosity, fluid saturation, organic maturity, geomechanical properties and initial gas in place.

Our petrophysical model for shale gas reservoirs is partitioned into organic matter, clay and non-clay minerals in the solids, adsorbed and free gas, together with capillary-bound, clay-bound and mobile water in the pore space. Vitrinite reflectance is computed in relation to the level of organic maturity (LOM) and kerogen density. Total organic carbon (TOC) is calculated using the Passey method (Passey et al., 1990). Effective porosity of shale gas reservoirs is calculated from algebraic expressions for solid and fluid fractions of the petrophysical model. Compressional and shear slowness logs are used to evaluate the geomechanical properties. Initial gas in place is calculated from free gas and adsorbed gas with porosity, fluid saturation, areal extent, thickness, adsorbed gas storage and organic matter.

The methods are successfully applied to a field case in Marcellus shale. TOC (wt.%) calculated by (sonic-density)/resistivity overlay methods for Marcellus Shale are 9.73% and 6.32%, respectively. TOC correlates directly to porosity and adsorbed gas in place occupied within the organic matter. For Marcellus shale, average density and sonic porosities are 6.25% and 3.46%, respectively. The comparison of Young's modulus and the minimum in-situ stress values between Marcellus shale and adjacent formations are used for the determination of the stimulation interval in the Marcellus Formation. Sonic and density logging suggest 2.22 BCF and 4.10 BCF as technically recoverable reserves with an 8% recovery factor. These results from Marcellus shale provide an improved understanding of economic development of unconventional reservoirs.
Innovative Use of Capillary String for Halite Cleanout in Sultanate of Oman
Authors: Veeken Cornelis , Alawi Ahmed , Ardia Kusela , Naabi Hajer , Janusz Norbert , Al Abri Ali , Ghanem Hassan , Fadhl Ahmed , Thakur Kapil
Published: November 2019

Following second stage depletion compression, more than 100 deep onshore gas wells operated by PDO in the Sultanate of Oman started suffering from downhole halite deposition. Halite scale blocks part of production and reduces well capacity by 20-80% depending on well specific conditions. Fresh water bullheading treatments were introduced to periodically dissolve the halite scale but in many cases treatments were applied too late or are not effective in preventing permanent blockage. In those cases, a cleanout using a work string is required to restore wellbore access and production. Historically, coiled tubing was used to remove halite scale via milling and fresh water jetting. Recently, 1/4" and 3/8" capillary strings were successfully deployed to reduce the cleanout cost and the volume of water lost to formation. This paper describes the experience with fresh water bulheading and the novel use of capillary string to clean wells that suffer from halite scale.
Removal of Condensate Banking from Different Formations Using Thermochemical Treatment
Authors: Al-Nakhli Ayman , Hassan Amjed , Mahmoud Mohamed , Al-Majed Abdulaziz
Published: November 2019

Condensate phenomenon occurs during gas production due to the reduction in reservoir pressure. In tight reservoirs, liquid banking causes an extreme damage and hydrocarbon production might be impaired due to liquid blockage. Therefore, stimulation treatments are applied to mitigate condensate damage and restore gas production. Several approaches are used to overcome liquid banking in gas condensate reservoirs. Gas recycling is one of the most effective techniques for mitigating condensate banking. However, at certain conditions, it might not be economical to use gas-cycling treatment, with the increasing demand on gas.

This work investigates thermochemical treatment to remove condensate blockage from different types of formation. In this work, rock samples from sandstone, shale and limestone formations were used. Thermochemical fluids that able to generate in-situ pressure and heat were used. Coreflooding tests were carried out by flooding rock samples with thermochemical fluids. Huff and Puff injection mode was applied to remove trapped condensate. Minimum of four cycles of injection and production phases were implemented. Sufficient soaking time was applied for all samples to ensure that the reaction between the injected fluids and the rock matrix reached to the equilibrium status. Pressure profiles were utilized to indicate the equilibrium status. The impact of formation type and number of injection cycles on the treatment performance were studied. The treatment efficiency was determined based on the volume of the removed condensate and the improvements of flow condition after the treatment.

The cumulative condensate recoveries were 72.97%, 68.09% and 43.38% for sandstone, limestone and shale samples, respectively. For all samples, the distribution of liquid recoveries with number of cycles are non-uniform. The incremental condensate recovery was reduced with production cycles, and more liquid removal was achieved during the first cycles of the chemical treatment. In addition, no formation damage was induced by the injected chemicals, which indicates that thermochemical fluids are compatible with the treated rocks. Reaction products of thermochemical treatment are able to stabilize the clay minerals and avoid clay swelling, particle migration and throat plugging. Overall, thermochemical treatment showed an effective performance in removing the condensate damage from limestone rocks. More than 60% of condensate banking can be removed using three cycles of thermochemical injection. In addition, the injected chemical showed minor effect on the rock integrity.
Successful Deployment of a New Intervention Technology Using a Reinforced, Flexible, High Pressure Hose; a World’s First
Authors: John Kevin Mathew , Morkved Marie L. , Grannes Ingvar , Haugvaldstad Jarle , Steinsholm Stian
Published: November 2019

This paper will discuss the design, qualification, testing and planning of a new intervention conveyance technology used to successfully remediate a failed down hole safety valve (DHSV).

The technology is a high pressure, reinforced, ¾ inch OD hose that is run on standard wireline equipment thereby reducing footprint, manning, cost and job time compared to other intervention methods. The hose has a working pressure of 12,500 psi with a tensile strength of 14,300 lbs. The system is gravity-fed into the well similar to a conventional wireline system and is spooled onto a wireline add-on drum with conventional wireline pressure control equipment (PCE). The difference compared to a standard wireline equipment is a modified add-on drum which includes a swivel for pumping, a purpose built stripper installed above the lubricator, and special inserts for the BOP.

Before mobilisation a series of tests were carried out to qualify the reinforced high pressure hose to ensure it was safe for interventions. Based on successful test results, the coil hose was mobilised and a total of 5 runs were carried out on the first job. These runs included jetting, spotting of chemicals and a caliper survey. The intervention successfully jetted 15% hydrochloric acid (HCl) over the DHSV, and through to surface. The job was an operational success and the DHSV inflow test, post treatment was successful.

The reinforced, high pressure coiled hose is a new conveyance technology that positions itself between wireline and coiled tubing. This technology can access wells on locations where running coiled tubing (CT) operations can be a challenge due to limited crane capacities and/or deck space. While coiled hose is not a replacement for CT due to its limited pumping rates (approx. 50lpm) and gravity feeding, it is suitable for spotting chemicals, N2 lifting and light cleanout operations.
An Innovative System Architecture for Real-Time Monitoring and Alarming for Cutting Transport in Oil Well Drilling
Authors: Selvaraju Senthil , Ramba Viswanth , Subbiha Senthilmurugan , Uppaluri Ramagopal , Dubey Pradeep Kumar , Musale Amol
Published: November 2019

A new system architecture is developed to provide decision aids on the prediction and prevention of downhole problems related to inadequate hole-cleaning and wellbore stability. The developed adoptive algorithm includes model calibration, real-time monitoring and alarm generation module when an anomaly is detected. An innovative approach is proposed to develop an unsteady state one-dimensional wellbore model, and model is capable do the real-time calculation of equivalent circulation density (ECD), and standpipe pressure drop (SPP).

The one-dimensional wellbore model is developed by integrating different sections of the mudflow. The unsteady one-dimensional wellbore model is integrated with Hershel-Bulkley model to predict both equivalent circulation density, and standpipe pressure drop (SPP), wherein the model parameter of the empirical equations are tuned to adapt to different types of rigs, mud systems, formations, and drilling scenarios. The mathematical model is first tuned with available historical data of the same well. Henceforth, the tuned model is used for monitoring the SPP and ECD profile across different sections of the wellbore.

The developed model is successfully tested in the oil field for real-time monitoring of ECD and SPP. The tuned model found to be capable of predicting the SPP below 5% error. The monitoring procedure of drilling activity was improved with a calibrated mathematical model. The system was able to detect the downhole problems related to hole-cleaning and hydraulic management, namely, excessive ECD, cutting accumulation in wellbore annulus and the possibility of stuck and kick in real-time. The false alarm generation due to sensor fault is found to be one of the challenging issues to resolve. Further, we observed that the data reconciliation and preprocessing of real-time sensor data could reduce false alarm for downhole complications. Further model accuracy can be improved by improving the accuracy of the sensors used for mud density, mud loss, and cutting size.

Unlike previous research works, in this work the annulus section of wellbore is divided into many small Continuous Stirred Tanks (CST) (i.e. Dynamic lumped parameter model) and they are connected in series to improve the accuracy of cutting transport model (i.e. to consider spatial variation of cutting concentration along the depth of the wellbore). Further simplified one-dimensional unsteady state wellbore model can be used for real-time calculation
Utilization of Artificial Neural Networking for Real-Time Oil Production Rate Estimation
Authors: Al Kadem Mohammad , Al Dabbous Mohammad , Al Mashhad Ali , Al Sadah Hassan
Published: November 2019

Oil flow rate testing is a crucial concept in oil fields where several methods facilitate well rate testing and measurement. Hundreds of multiphase flow meters (MPFMs) have been utilized to enhance the accuracy of testing measurement and provide reliable data for all fields. Even though these meters are of paramount importance, they require frequent preventive maintenance, calibration and manpower. In this paper, an Artificial Neural Network (ANN) model is developed as a backup tool to replace MPFM measurements when the device becomes defective or inoperable.

Several correlations have been established to facilitate oil well testing at minimal cost; relying on surface production parameters to allow enumerating the oil flow rate without installing expensive equipment. An ANN model was developed using real-time wellhead parameters measured from equipment installed at the surface to designate properties and characteristics per reservoir. The ANN model was calibrated, tested and validated to achieve the most accurate results. The model was further optimized to attain a reliable tool for real-time rate estimation.

In this paper, assessment of various correlations was conducted to compare the accuracy of each ANN-related empirical equation in five different datasets. The assessment also covers a wide range of data. More than thousands of data points from MPFM were compared to Towailib, Marhoun and Gilbert correlations, and showed highly deviated values with an average relative error of more than 40%. The same sets of data were tested using the newly developed optimized ANN model. The results from the model resulted in an average relative error of 3.7% compared with the MPFM rate measurements. Therefore, the new ANN model presented in this paper shows highly accurate results.

The developed model contributed to enhancing testing efficiency and optimizing production. Indeed, utilizing this model is an essential practice for production engineers to validate well tests if prompt outcomes are desired and another reliable tool to estimate real-time rate production when metering device is down.
3D Petrophysical and Geomechanical View for Enhancing Hydraulic Fracturing of Horizontals and Highly Deviated Wells
Authors: AL Isaee Omar , Chavez Florez Juan , Ali Nada , AL Ghatrifi Rawan , Al-Yaqoubi Mazin , AL Abri Ahmed , AL Hinai Mohamed
Published: November 2019

In Oman, the unique geological properties of the reservoirs require different fracture strategies and technology deployment to make them commercially viable. Highly deviated wells, with multiple hydraulic fractures, have been identified as key technology enabler for the development of tight gas accumulations in Oman. The main objective of this study is to generate a 3D petrophysical and geomechanical view of the reservoir, to have a better understating of Hydraulic Fracturing for Horizontal and Highly Deviated Wells

The comprehensive amount of data captured during the initial implementation phase of highly deviated wells covering reservoir characterization, fracture geomechanics as well as production logs in combination with the existent data captured in vertical wells, proves to be complex to analyze due to the volume of information and the multi variable nature associated with fracture and inflow predictions. A methodology was required where correlations and tendencies were identifiable at structural level, covering all target gas accumulations using all the static and dynamic captured data. The definition of a 3D Grid Visualization Block (3D-GVB) was introduced where all the captured parameters were distributed for analysis and interpretation.

As a result of the appraisal and initial field development with vertical wells, it was possible to identify tight accumulations that will require dedicated highly deviated wells for its development. The initial phase of the implementation of highly deviated wells proves to be challenging, as the observed heterogeneities on geomechanical and petrophysical properties across the target gas accumulations, combined with differential depletion and the wells orientation to generate transverse fractures, creates a complex environment for fracture initiation and propagation, impacting not only fracture deployment but inflow deliverability of this wells. This paper will describe how the methodology uses a cycle of data analysis and interpretation to identify tendencies, that will lead to correlation and new algorithms that are retrofitted on the 3D-GVB platform, leading to optimization of well positioning at structural level, drilling and completion of this highly deviated wells.

It will be described how this methodology is used for well positioning at structural level, to define well architectures oriented to enhance not only drilling, but also hydraulic fracturing and hydrocarbon deliverability on highly deviated wells.
Reservoir Connectivity Analysis for a Complex Channelized Reservoir to Reveal By-Passed Pays: Serpent Field, Offshore Nile Delta, Egypt
Authors: Sakran Shawky , Gaafar Gamal , Latif Shaker , Taman Saad , Abdel Razek Ahmed
Published: November 2019

The West Delta Deep Marine concession (WDDM) lies offshore in the Deep water of the present day Nile delta. WDDM consists of many Pliocene submarine channel complexes. The Serpent field is one of those slope marine channels and consists of two separate channels namely channel 12 and channel 13. Channel 12 is divided into three compartments by gravitational faults and channel 13 is composed of two compartments separated by stratigraphic barrier. Gas water contact (GWC) in channelized turbidities reservoir might create an intricate reservoir relationship. Gas water contact becomes complicated when the faults and the facies lateral change provide seals. Those hydrocarbon contacts depths become unpredictable without a distinct system to understand the cause of those variable contacts. Water break-through occurred earlier than expected in Serpent production wells as there was no proper modeling for reservoir facies heterogeneity and facies associated petrophysical parameters. A further compartmentalization of channel 12 arose as the sealing capacity of the gravitational faults cast a doubt over channel-12 compartmentalization and the connected gas initial in place (GIIP). The geological foreknowledge of Serpent field, the production issues and the dire need for further development plans in Serpent field were the motives to initiate this study. Integrated study was designed to answer the unsolved challenges of characterizing the reservoir heterogeneity and faults' sealing capacity. 3-D (three dimensional) high quality seismic data and different seismic attributes were integrated with different well data to build a robust 3-D static model. Static model was the way to elaborate the facies accurate distribution and the different petrophysical parameters in Serpent reservoir. In addition, the 3-D static model was used in the prediction of the faults' sealing capacity through the fault rock facies, fault rock petrophysical properties and transmissibility. In a nutshell, the resultant static model answered the field's issues regarding the early water production, facies heterogeneity and Successfully isolate the different reservoir compartments then run into prediction to assess the potential of the existing well-stock and any future development plans in Serpent field.
Case Study of Self-Adjusting PDC Bit Technology Reducing Drilling Dynamics, Improving Performance and Avoids NPT in the Western Desert of Egypt
Authors: Hafez Mohamed , Aboulfotouh Mohmoud , Abd El Moneim Mohamed
Published: November 2019

The 12 ¼" section in the western desert, Bapetco concision is challenging to be drilled as of the highly interbedded carbonate and shale formations, which are known to exhibit high levels of vibrations (torsional and lateral) associated with high drilling torque. Such high drilling torque lead-to increasing the Mechanical Specific Energy (MSE), reduction in Rate Of Penetration (ROP) and early dull for used bits. While in some cases it can even lead to twist-off incidents and major Non- Productive Time (NPT) events.

Customer NPT can cost up to $ 450k in case of sidetracking the well. In case the Bottom Hole Assembly (BHA) stands the vibration level, the parameters would have been controlled losing ROP which resulting in lost time that cost at least $ 35K.

The solution of adjusting the depth of cut downhole (Self-Adjusting) which have been newly introduced to the market targeting to decrease downhole vibrations, specially torsional vibrations and allow smoother transition between lithologies with different compressive strength and help in a smooth transition between the different layers while optimizing the depth of cut control

When the self-adjusting feature engages with rock for steady state drilling, the feature gradually retracts, controlling DOC to find the optimal exposure of the element for the current drilling parameters and formations. As dynamic instabilities occur, the self-adjusting feature reacts at fast time scales to mitigate the event. This should result in optimizing the bit response to deliver the best performance real time, decreasing the torsional vibration, NPT & MSE. This will lead to increase the drilling efficiency. The 12 ¼" PDC bit with the self-adjusting was tested with one Shell/Bapetco in the western desert wells, resulting in decreasing the vibration levels, decreasing the MSE hence increase the ROP 57% compared to average of the field which resulted in significant reduction to the drilling cost compared to the offset wells while achieving 35K of savings compared to the best offset

Below will present how the latest self-adjusting PDC technology had a significant impact on drilling time and cost savings by mitigating drilling dysfunctions that could result in unplanned trips and drilling inefficiencies if not addressed in a timely manner
Transforming Local Sands into a Reliable, Alternative Proppant Source
Authors: Khamatnurova Tatyana , Nguyen Philip , Inyang Ubong , Shen Dong , Gashimov Ruslan , Larsen Travis
Published: November 2019

An abundant supply of low-cost local sands and their associated logistical advantages have incentivized operators over the last couple of years to use them in hydraulic fracturing treatments of unconventional reservoirs. Local sands are known for their low crush strength and high angularity and can contain other mineral particulates, besides quartz, compared to high-quality sands. This paper describes laboratory tests to demonstrate that low-quality sands, when treated with a binder, can generate stable, highly conductive channels within a simulated propped fracture, which could help maximize and also maintain production of hydrocarbons from the reservoir.

Laboratory experiments were conducted to evaluate the performance of local sands when used in aggregate structures, simulating proppant ridges or partial packs formed in a propped fracture. These aggregates were formed by coating sand grains with a binder and placing them in molds to be cured before testing. The sand aggregates were then placed in API conductivity cells to determine the effect of closure stresses on aggregate height, size expansion, binding agent concentrations, and conductivity measurements. Cyclic stress testing was also performed to evaluate the stability of the aggregate structure and conductivity retention of flow channels as the aggregate was subjected to varying stress loads.

The results obtained during this study indicate that the flow capacity of conductive channels prepared from proppant aggregates using local sands is comparable to those prepared using high-quality sand or high-strength manufactured proppant. Fines migration from proppant crushing within the aggregate was observed not to be a concern because sand grains connected and encapsulated by the binder helped lock the crushed sand together. Despite having diminishing permeability within the aggregates, flow capacity of solids-free channels between aggregate masses dominates flow through the propped fracture, making formation of proppant aggregates with high-quality sand or high-strength proppant (HSP) unnecessary.

This suggests that using local sands, despite their low crush resistance, during fracturing treatments can effectively enable well production by forming highly conductive voids or channels on top of the settled sand packs in the propped fractures in a shale reservoir.
Development of Novel Composition for Controlling Moderate to Severe Losses
Authors: Wagle Vikrant , Kalgaonkar Rajendra , AlYami Abdullah , AlKhalaf Sara
Published: November 2019

The loss circulation composition comprising the nanosilica based dispersion and a chemical activator has been designed to treat moderate to severe losses. The nanomaterial used in this loss circulation composition is an environmentally friendly material and a chemical activator. The loss circulation composition is so designed so as to give delayed gelling of the nanoparticle based dispersion. A major advantage of this technology is its ability to place the loss circulation treatment composition in to the target loss circulation zone before the nanoparticle based dispersion gels up. Premature gelling of the nanoparticle based dispersion would avoid premature setting of the treatment fluid before it reaches the target zone. The newly developed system can be used effectively up to 300°F.

In this paper, experiments have been performed with three different types of nanoparticles differing in their surface charges and particle sizes. Two negatively charged nanoparticle-based dispersion with a particle size of 5nm and 17nm respectively and one positively charged nanoparticle with a particle size greater than 17nm have been evaluated as loss circulation materials. Two different types of chemical activators, one organic and the other inorganic have been used in this study and their effect on the gelling time has been evaluated. The gelling time experiments have been done at four different temperatures viz. 150°F, 200°F, 250°F and 300°F. The effect of activator concentration and different shear rates on the gelling time of the three nanoparticle-based dispersions has been studied. Permeability plugging tests have been performed on the three nanoparticle-based dispersions using 2mm slotted disks and their effectiveness in controlling moderate to severe losses has been evaluated

The loss circulation composition can be designed so as to control its gelling time by adjusting the activator concentration. The results show that a specific gelling time of the loss circulation composition can be obtained to achieve a predictable and controllable pumping time. This pumping time can range from a few minutes to several hours at over a wide range of temperatures. A predictable gelling time would allow the nanoparticle-based dispersion to remain pumpable for sufficient time before being placed in the loss circulation zone. The loss circulation composition which turns from a liquid to a gelled solid is then expected to seal off the loss circulation zone and thereby prevent fluid loss.
Best Operational Practices to Optimize the Time & Cost for Drilling in Appraisal Unconventional HP/HT Wells Across Deyab Formation, Abu Dhabi - UAE
Authors: Ruiz Fernando , Hebish Ayman , Negoi Adrian , Al Hendi Mohammed , Hamdy Ibrahim , Nunez Ygnacio , Mandal Vivekananda , Al Samahi Musabbeh , Al Hadidy Khaled , Al Awadhi Eman , El Yossef Bassem , Coscia Marco
Published: November 2019

This paper has the recommended procedures to be carried out in each phase: Surface, Intermediate I and II, horizontal and completion with frac string, for Unconventional Appraisal HP/HT wells across Deyab formations in Abu Dhabi (UAE), as well as the technology to be used and avoid, to drill the wells saving time and money helping to make a rentable project.

Due to the information received of the zone was scarce, in addition the first well in the area (offset well and taken as a reference) had many operational problems. The operations during drilling the next three wells in PAD # 1 were recorded, analyzed and optimized, resulting in a learning catalog for the area, saving a considered quantity of rig days with a huge impact in the budget and the most important, the exposure of the crews/people at the location was minimized to this hazard environment.

The PAD# 1 has 03 horizontal wells, the design is Heavy Casing Design, where each phase has its characteristics to be drilled and cased. The reservoir consists of 03 cl early identified formations: Jubaila, Hanifa and Tuwaiq Mountain into the range from ± 12330 ft. TVD to ± 12900 ft. TVD. Reaching the targets with horizontal wells from 16,000 ft. MD to 17,500 ft. MD.

After analyzing each section and getting the recommendations from different service companies and specialist, the changes were implemented in the next well regarding drilling fluid MW, BHA's design, bit type & design, wiper trips, slurries, trajectories, etc. taking as result drilling wells more complicate d without operational issues, in deepest formation, drilling more than 1000 ft. MD and 600 ft. TVD, and saving 3.25 MM$ and 15.2 days per well

The PAD # 1 in Deyab field, is the pioneer for the initial development of fracking in UAE. There hasn't had a drilling procedure in detail to reach the target without having issues. This new concession has been already of interest to be developed in conjunction with the National Company, so create a Drilling Learning Catalogue as add value at the moment to handover the wells is a must.
High Resolution Reservoir Quality Prediction at the Reservoir Scale Through Diagenetic Modelling
Authors: Ortenzi Andrea , Camocino Davide , Daturi Cristina , Geloni Claudio , Pontiggia Marco , Valdisturlo Antonio
Published: November 2019

The reservoir quality prediction is carried out at the exploration scale through software that try to model the diagenetic evolution of the reservoir. The input data are quantitative petrographic data, core analysis results and the burial and thermal history of the wells either 1D or 3D (PSM). The procedure starts from the calibration of the model on a well with cores or sidewall cores for petrographic-diagenetic data and RCA and with a calibrated burial and thermal history. Once calibrated, the model extends to the whole area of interest following the 3D burial and thermal history model of the reservoir.

The extension of the approach to the reservoir scale requires a dedicated work-flow that comprises the following points: -Identification of the main diagenetic issues from petrographic studies;-Use of the information coming from logs of the non-cored wells in a diagenetic perspective; this step comprehends the realization of detailed CPI of wells and, if necessary, additional mineralogical analyses in order to fix a valuable mineralogical model;-3D burial and thermal history reconstruction at the reservoir model scale using the reservoir model surfaces; the step implies the reconciliation of the regional explorative model with the layers and cell dimension of the reservoir one;-Modelling of specific diagenetic phenomena through transport-reaction models, in order to assess the areal distribution of diagenetic drivers in the reservoir to be used as trends; as an example, carbonate cementation though faults is one of the issues; in this step, also the structural evolution of the reservoir is a key point;-Reservoir quality prediction maps of the reservoir layers;-Use of the maps as soft drivers in the reservoir models and results comparison with other model scenarios (e.g. inversion-based model) ;-Evaluate the match with model prognosis and new well results

The work-flow was applied to a Cretaceous reservoir in West Africa. The reservoir quality variations are usually subtle at the reservoir scale and the effect of local variables may be strong. The resulting reservoir quality maps provided trends for properties distribution in the reservoir model obtaining remarkably different results compared to the inversion-based distribution and providing additional data for uncertainty analysis.

The reservoir quality prediction at the reservoir scale implies a new approach to the diagenetic problems and to the integration of log and petrographic data. The work-flow has to encompass all data in a collaboration space in order to produce a valuable tool for reservoir models.