bluuebunny/crossref_metadata_2025 huggingface dataset:
Root Cause Failure Analysis as a Tool for Investigating Operational Failures: A Case Study
Authors: Scolnick Spencer E. , Garrett Jonathan C. , Griffith Steven L. , Ward Kevin K.
Published: September 2015

Production liner cementation in deepwater wells is critical to contain formation pressures and provide zonal isolation. This is especially challenging in the Gulf of Mexico because of depleted zones, small drilling margins, and HPHT reservoirs. Failure to achieve zonal isolation with the primary cement job leads to added cost and time for remedial operations. A recent primary cement job failure in the Viosca Knoll Block, located in the Gulf of Mexico, prompted the use of an established tool, Root Cause Failure Analysis (RCFA), in a novel way to identify the causes of the incident and avoid repeating the same mistakes in future wells.

A team of operations and engineering personnel was assembled to investigate the cause of the primary cement job failure that resulted in nonproductive time and cost of approximately 7 days and $3 MM, respectively. RCFAs have typically been performed on equipment failures; however, this RCFA was conducted by the operator on a non-equipment related failure.

The RCFA team initially collected data available from both the planning and operation phases of the job in order to identify which elements of the cementing process contributed to the cement job failure. After identifying the root cause, the team communicated learnings to office and rig-based personnel, developed a new tool for real time monitoring of primary cementation, and adjusted plans for upcoming primary cement jobs. The findings from the RCFA were applied to a well on another asset owned by the operator, with which the production liner was successfully rotated throughout cementation for the first time.

The RCFA identified that the cement job design was not a contributing factor; instead, the root causes were operational and started during circulation of drilling fluid prior to cementing operations. The learnings from the RCFA were transferred to both office and rig-based personnel, influencing engineering and operations plans for subsequent wells. Furthermore, the investigation identified previously unknown issues and showed that the use of the RCFA process was an effective approach that can be standardized and scaled to determine root causes of future operational failures.
Predicting and Optimizing ROP in Competent Shale by Utilizing MPD Technology
Authors: Mammadov Elvin , Osayande Nadine , Breuer John , Al-Hashmy Wamidh
Published: September 2015

Advanced Managed Pressure Drilling (MPD) technology was used onshore in Western Canada to optimize ROP while drilling horizontally through the potentially sour shale formation using a low solids, low density synthetic base mud system. The Montney shale formation is very challenging to drill conventionally and has the potential for drilling into high pressure fractures which may contain sour gas. The overall objective consisted of using a lower density synthetic base mud system to optimize the ROP, thereby saving on overall drilling costs by reducing the number of drilling days and also drill the well safely due to the possibility of high pressure fractures and potentially sour gas. The main challenge was to increase ROP while still maintaining a constant bottomhole pressure to prevent any gas inflow into the wellbore.

In order to optimize drilling efficiencies and save on drilling time, advanced MPD technology was applied in combination with a low density (770 kg/m3) synthetic based mud while holding surface back pressure (SBP) in dynamic and static conditions to maintain a constant bottomhole equivalent circulating density (ECD). The system's annular pressure control mode was used to hold a desired ECD at a pre-determined position within the wellbore; In this case the heel was chosen. Constant bottomhole pressure operations were maintained throughout the entire project. The desired ECD was achieved and the well was kept at balance with the pore pressure. The advanced MPD system also provided the ability to monitor, detect and control an influx at the bit much earlier than conventional MPD and drilling systems which provided additional safety to the location. While drilling conventionally the ROP was extremely slow averaging 3.32 m/hr. The results greatly improved using advanced MPD technology with average ROP's between 7.4–10.5 m/hr.

This application also brought value to the project by reducing mud costs, increasing overall ROP as compared to conventional offset ROP data, maintaining constant bottomhole pressure with flexibility to adjust pressures as the well dictated, increasing safety through detection and control of micro influxes while drilling, reducing bits used as compared to conventional offset bit record data and minimizing any gas to surface. Achieving the goal of increasing the ROP and safely drilling the well to TD reduced the number of drilling days by at least 13 days, thereby reducing the overall AFE of the well.

This paper will include engineering analysis of the project compared to offset data along with graphs and tables. It will further include detailed explanation of pre-engineering and execution methods of advanced MPD in order to achieve ROP optimization and reduce your drilling cost.
Digital Rock Technology for Quantitative Prediction of Acid Stimulation Efficiency in Carbonates
Authors: Klemin Denis , Nadeev Alexander , Ziauddin Murtaza
Published: September 2015

The complex pore structure and porosity in carbonate rocks have a strong influence on the stimulation efficiency of the acid. Recently, it was shown that nondestructive tracers can be used to predict pore volume of acid to breakthrough (PVBT) for both plain and emulsified acids [1, 2]. The present study explores the use of digital rock technology to simulate tracer injection in carbonate rocks. The accuracy of the digital rock method is compared to the laboratory measured values for five carbonate rocks of different porosity types and heterogeneity scales. The digital rock simulations are performed by an industry-unique direct hydrodynamic pore flow simulator that operates on pore geometries from digital rock models obtained from 3D scanning electron microscope images. The pressure-volume-temperature and rheological models used in the simulator represent real treatment and reservoir fluids. Fluid-solid interactions are introduced using distributed microscale wetting properties. The simulator uses the density functional approach applied to the hydrodynamics of complex systems. The simulations are used to calculate a measure of the accessible rock volume which is then used to predict the acid response.

Conventional laboratory testing methods require large volumes of formation rocks for optimization of acid type and volume and it often prohibitively expensive. The digital rock methodology has the potential of significantly reducing the required volume of formation cores, which could be an enabler for more frequent carbonate porosity specific stimulation optimization. The present study explores the limits of its applicability.
Flow-loop Testing of Subsea Produced Water Quality Monitoring Sensor Prototypes
Authors: Yin Xiaolei , Moore Patrick , Gul Kamran , Lachance Jason
Published: September 2015

Re-injection of produced water can be a cost-effective way of disposing produced water and improving hydrocarbon recovery for subsea production and processing systems in deeper water or with long tieback distances. Injecting produced water with high oil-in-water content and suspended solids into a well can be detrimental to relative permeability in the formation near the wellbore region causing loss of well injectivity over time. Monitoring re-injection water quality trends can provide an early indication of injectivity decline and potentially avoid loss of an injection well.

As the industry moves closer to having a fully-functioning subsea production and processing system, there has been an increased effort in developing reliable in-line subsea Produced Water Quality Monitoring (PWQM) technologies. Such monitoring sensors can measure the quality of re-injection water in terms of oil and solids content (size and concentration) thereby facilitating performance monitoring of subsea separation and produced water treating systems by identifying upset conditions.

Development efforts to meet subsea PWQM requirements for produced water re-injection application included: (1) development of subsea sensor concepts with active cleaning systems to enable long term operation without compromising performance, and (2) extension of the Oil-in-Water (OIW) measurement range significantly to support subsea production/processing and produced water reinjection applications. The new sensor designs that were developed primarily for subsea application for improved measurement performance and with self-cleaning functionality can also be used topsides.

Two different PWQM sensor prototypes were developed to meet the subsea PWQM requirements. The measurement performance of both prototypes was verified in a flow-loop by comparing the measurement readings with known reference. The impact of variations introduced in test conditions such as changes in pressure, temperature, salinity, and flow velocity on the performance of the prototypes was also investigated. The active cleaning systems were also tested to examine their effectiveness under normal and simulated fouling conditions.

The paper discusses the technical gaps in subsea PWQM technologies, flow-loop testing of the PWQM sensors prototypes and the key test results.
Identifying Leading Indicators to Address the Risk of Drilling and Completions for Shale Gas
Authors: Tamilselvan Prasanna , Das Bibek
Published: September 2015

A successful drilling and completions operation for Shale Gas is the key to ensure wellbore integrity throughout the life of the well. Drilling for shale gas involves a lot of uncertainty regarding the geology, geography and well geometry (3G's). It is thus imperative to identify the leading indicators for failures to avoid the costly measures later required to solve operational problems and reduce non-productive time. However, the uncertainty factors (3G's) vary for different regions like Marcellus and Barnett shale; as well as for different wells in the same region as seen in the Eagle Ford shale play. Hence it becomes difficult to implement the know-how of one region to another region.

This paper proposes a novel framework to identify leading indicators to address the risk in shale gas drilling and completions. The proposed framework is divided into three main parts: (i) collection of past failure data, 3G parameters and real-time monitoring data; (ii) estimation of real-time damage growth using the proposed model that combines physics based failure model and data collected from previous stage; (iii) identification of leading indicators and estimation of reliability parameters and updating those to the “live” databases. The paper includes a case study on casing failures related to shale gas operations.

The specific failure mechanism that is often seen in shale operations is brittle longitudinal splits of couplings. This paper discusses the failure analysis of longitudinal splits of P-110 casing. The study then identified the leading indicators based on the failure analysis. The sensitivity studies on variability of initial damage level and loading on the stochastic damage propagation model are also conducted.

The sensitivity study results show that the damage propagation is largely influenced by the variability of initial damage level and loading process. This paper also suggests leading indicator mapping process. This includes maintaining a database on mapping of generic failures and their corresponding leading indicators. This enables the analyst to use the data from different regions interchangeably by extending the boundaries of failure analysis.
Long Range Electromagnetic Telemetry Using An Innovative Casing Antenna System
Authors: Chen Jiefu , Li Shanjun , MacMillan Clayton , Cortes German , Wood Drew
Published: September 2015

Wireless data transmission is an essential part of measurement-while-drilling (MWD) or logging-while- drilling (LWD). It can be achieved by several different technologies, such as mud pulse telemetry or electromagnetic (EM) telemetry. Compared with mud pulse telemetry, EM telemetry has been proven to have better reliability and relatively faster rates of data transmission. However, EM telemetry may suffer severe signal attenuation when conductive formation layers exist between bottom hole assembly (BHA) and the surface.

An innovative casing antenna system has been developed to alleviate the signal attenuation issue of EM telemetry. A transceiver is set on the surface connected with two coaxial cables. One cable is externally attached to a casing string and connected to the bottom of the casing; the other cable is placed at surface connected to either the blowout preventer (BOP) or a metal stake driven into the ground with a certain distance away from the rig. Telemetry signals are propagating between the surface transceiver and the borehole transceiver via underground formation.

The new system essentially measures the potential differences between the bottom of the casing string and one point near surface. On the contrary, conventional EM telemetry measures the potential differences between two locations on the surface. The innovative deployment of this casing antenna makes the new telemetry system be able to avoid heavy signal attenuation caused by any low resistivity layers above the bottom of casing, and consequently it has much larger operation depth than conventional EM telemetry. Numerical studies also show that this new telemetry technology has less signal drop as the working frequency increases; in other words, it can provide higher rates of data transmission.

In this paper we will describe the setup of the casing antenna system, explain the working principle of this innovative method, and compare the new system with traditional EM telemetry system. Numerical simulations as well as filed data will be given and discussed to demonstrate the advantages of this new technology over conventional EM telemetry.
Revealing the Benefits of the Intelligent Well Pad Program for Onshore Shale Assets
Authors: Krome J. D. , Bloom M. H. , Swanson A. B. , Anthony D. , Derise S. , Rightmire L.
Published: September 2015

Though many of the US shale plays have been developed in just the last few years, there remain new producing assets that lack the latest technologies and best-in-class working practices. Retrofitting these assets with now-commonplace digital oilfield-type automation, information technology (IT), and work practices have revealed significant benefits to BHP Billiton (BHPB) in the Eagle Ford shale. This paper will describe how BHPB, after purchasing the Petrohawk Eagle Ford shale assets, recognized the potential for improvements, and used Karnes County wells as a demonstration area for its Intelligent Well Pad Program (IWPP).

A multi-disciplined team evaluated the opportunities and implemented a comprehensive program of facility redesign, wellsite automation, IT & Telecommunications, and a 24/7 surveillance center. A detailed assessment, with all key stakeholders, yielded a fit-for-purpose program, detailed and tailored for this specific application.

The IWPP, deployed over a 12-month period, is showing improved results in HSE (via reduced personnel exposure to driving on dangerous rural roads and well pad hazards), Production (via reduced downtime), and Cost (via increased well count / operator). Based on these early positive results, BHPB are now developing and tailoring its IWPP solutions and working practices across all of its shale assets, as a key aspect of greenfield well pads.
Making the Impossible Possible with MPD Application on 0.4 ppg Mud Weight Window – A Case History Successful Automated Managed Pressure Drilling, Managed Pressure Run 11 ¾” Liner & 9 5/8”Liner (Tieback Liner), and Managed Pressure Cementing in a Semisubmersible Offshore Sarawak Malaysia
Authors: Tang Jose , Prasetia Andi Eka , Gallo Fernando , Rojas Freddy , Rubianto Irwan
Published: September 2015

The JST-1 well is an offshore High Pressure and High Temperature (high pressure by gradient which was more than 0.1 psi/ft) exploratory well, located in the block SK 301A.

The primary objective was to evaluate the hydrocarbon potential in Cycle VII and Cycle VI, at the depth of 2374 and 2794 mTVDDF respectively with anticipated reservoir pressure of 5476 and 6898 psi with temperatures from 226 to 264 °F at well TD 3477mMDDF/TVDDF the pressure and temperature was predicted to be 9276 psi and 302 °F.

The well was initially planned to be drilled to 2979 mTVDDF in 12 ¼” hole section and 8 ½” hole section until 3477 mTVDDF. The degree of uncertainty in JST-1 pore pressure and fracture gradient estimates are highly uncertain. This was due to the reason that the offset wells, S-1 and L-1 are very far away from JST-1, approximately 33 km away to the North West and 35 km to the North East respectively. In addition, none of the offset wells have been drilled deeper than 2879 mMDDF. Therefore, high case pore pressure and fracture gradient estimates were used for the well design and planning.

Based on cementing simulation for the 11 ¾” liner, 9 ⅝” casing cementing jobs, the resultant cement slurry Equivalent Circulating Density (ECD) will fracture the formation while the cement is pumped into the open hole. Hence, the Managed Pressure Drilling (MPD) method was used to drill hole sections lower than 13 ⅜” casing as well during the cementing job and running in hole with 9 ⅝” casing.

This paper aims to describe the application of Automated MPD on this specific well from conceptual to planning to finally execution. Moreover, with the intention to share the challenges observed during execution as well as the decisions taken to overcome these challenges and finally the 5 steps strategy to ensure the well was stable.
Maximizing Well Deliverability in the Eagle Ford Shale Through Flowback Operations
Authors: Deen Toby , Daal Johan , Tucker James
Published: September 2015

Flowback procedures for wells producing from sub-normally or normally pressured reservoirs are usually straightforward and non-technical due to the short flowing periods that are inherent with low pressure wells. Over-pressured formations can naturally flow for several months and even years. However, uncontrolled procedures can potentially affect the well productivity and its profitability. Flowback techniques for wells flowing from over-pressured reservoirs can vary widely and have a significant impact on short and long term economic performance.

This paper focuses on the evolution of flowback operating procedures for wells in the Eagle Ford shale play and highlights how these procedures can impact short and long term well performance. The workflow demonstrates how choke management, or drawdown strategies, can influence potential damage mechanisms in the reservoir, completion and wellbore. Techniques are then presented for using rate transient analysis (RTA) that allows for a robust understanding of early time well performance while also monitoring for damage downhole. The data shows that using RTA with high frequency data to help drive operational decisions during the flowback period can deliver optimal drawdown procedures and maximize well deliverability. This in turn maximizes time sensitive economic metrics by taking full advantage of variables like the well's completion efficiency and stimulated volume.

The drawdown management workflow outlined in this paper has proved to significantly outperform predetermined choke procedures that have historically been common practice in industry. Results also show how practical field applications of technical interpretations can be used on a daily basis to significantly increase value and drive operational efficiencies in the field while minimizing the potential risk of damaging the completion.
Liquid Loading of Highly Deviated Gas Wells from 60° to 88°
Authors: Alsaadi Y. , Pereyra E. , Torres C. , Sarica C.
Published: September 2015

Liquid loading, a common problem in matured gas fields, is investigated experimentally in highly deviated gas wells. The experiments were carried out using air and water in a 3-in ID pipe at well deviation from 60° to 88° from vertical. Pressure gradient and liquid holdup were measured, and flow pattern characteristics as well as onset of liquid loading were observed using video recordings. The results shown a significant effect of the deviation angle on the onset of liquid loading. Benchmark of the results with several two-phase mechanistic models show poor predictions for the pressure gradient but good agreement for liquid holdup.
How Far Can We Push the Boundary of Horizontal Drilling? A Rivalry Between Wellbore Friction and Drillpipe Buoyant Weight and Stiffness
Authors: Mehrabi Mehran , Miska Stefan
Published: September 2015

To estimate the maximum attainable reach for a horizontal wellbore one needs to investigate the rivalry between the amount of available driving force and the opposing frictional forces. As we provide more driving force through further slack-off, we are more likely to buckle the string and create large normal contact forces, which result in additional tangential frictional forces opposing the forward motion of the BHA. In other words, all the provided driving force will not be transmitted to the desired point (i.e. drillbit) along the string. The greater the stiffness of the drillpipe, the later it buckles and comes into contact with the wellbore wall to create additional normal forces. However, greater stiffness might come with greater weight, as is the case for Steel Drillpipe (SDP) compared to Titanium Drillpipe (TDP), Aluminum Drillpipe (ADP) and Composite Drillpipe (CDP).

In this study a new approach for modeling the coupling between tangential frictional force and normal contact force between wellbore and helically-buckled drillstring is developed. The validity of the model is confirmed with experimental data available in the literature. The axial force transfer capability of drillstrings made of SDP, TDP, ADP and CDP are compared. For a limited amount of compressive force provided at the beginning of the horizontal section, different categories of pipes (in the horizontal section of the well) take on different configurations. In addition, along a drillstring some parts remain straight, while some parts buckle helically or sinusoidally. This makes different drillstrings transfer the same amount of provided load differently. In practice, we are able to supply a limited amount of compressive load close to the critical lock-up load in the vertical/slant section of the wellbore. Moreover, below a minimum weight on bit (WOB) drilling becomes impractical. After simultaneous consideration of different buckling modes along the entire drillstring, it is quantitatively shown under what condition ADP can be considered as a superior option over CDP to be used in the horizontal section; and why ADP and CDP have shown a remarkable increase (almost two to three times larger) in the attainable horizontal reach compared to TDP and SDP. This article helps drilling engineers to design an optimum hybrid drillstring for ultra-extended-reach-wells.
Case Studies Validate the Effectiveness of Aluminum-based HPWBM in Stabilizing Micro-Fractured Shale Formations: Field Experience in the Peruvian Amazon
Authors: Arambulo V. H. , Colque J. N. , Alban E. D. , Ahmed R. M.
Published: September 2015

One of the most important functions of drilling fluids is to maintain adequate wellbore stability until casing is run and cemented properly. Lack of wellbore stability generates an enlarged non-homogeneous elliptical weaker borehole. This non-cylindrical shape of the wellbore leads to complex drilling problems such as poor hole cleaning, high solids production, stuck pipe, unsuccessful wireline runs, poor cement bond representing large cost to operators.

Micro-fractured shale formation represents a challenge due to its natural lack of stability when exposed to conventional water-based mud (WBM). As a solution, oil-based mud (OBM) becomes a technical option to overcome the issues observed with conventional WBM. It tremendously reduces the chemical interaction with micro-fractured shales. However, environmental constraints of the OBM makes this option non-applicable for environmentally sensitive areas. According to recent publications, with similar complicated environments, Aluminum-Based High-Performance Water-Based mud (HPWBM) has shown good performance with features closely comparable to that of OBM.

The Peruvian Amazon has the largest Peruvian oil and gas reserves. However, it is located in an environmentally sensitive area marked by a large biodiversity and native communities. Environmental concerns related to drilling activity are very restrictive. Furthermore, most operations are performed as “offshore on land” (i.e., helicopter-transportable operation) where drilling fluid management cost strongly affects the final Well’s Authorization for Expenditure (AFE). Aluminum-based HPWBM has been successfully introduced recently in the Peruvian Amazon for drilling vertical and deviated wells resulting in considerable improvement in drilling performance and goal achievements. Issues related to shale instability were previously reported and financial losses forced operators to use Aluminum-Based HPWBM to reduce non-productive time and associated costs.

Two groups of case studies from four wells drilled in Blocks 8, 56 and 88 blocks of the Peruvian jungle are presented in this paper. A Wellbore Quality Index (WQI) tool and Key Performance Indicators (KPI) are introduced to make comparison between aluminum-based HPWBM and previously used (i.e. conventional) fluid systems and to validate the effectiveness of the aluminum-based HPWBM system in stabilizing micro-fractured shale formations. A proper fluid design was selected during the planning phase of each project and fluid properties were monitored at the rig site to evaluate performance. In addition, wireline logging, casing runs, trips, wellbore quality and drilling performance were closely monitored to examine the impact of using aluminum-based HPWBM. Results show tremendous performance improvement introducing a new benchmark in drilling operation in the Peruvian Amazon.
A Case Study of Using Expandable Liner Hangers and Advanced Cementation Techniques for ERD Wells in India
Authors: Lobo Monali , Singhal Ashish , Lang Clifford , Kolay Jayabrata , Sinha Pankaj , Kant Ravi , Varghese Roy , Doodraj Sunil , Li Jason , Kumar Animesh , Kestwal Ashish , Vaibhav Ankit
Published: September 2015

This paper explains the successful execution of Expandable Liner Hanger and primary cementing job for ERD wells in Rajasthan block of North-West India. One of these wells has the longest horizontal 6in. hole section in the Indian Subcontinent. Zonal isolation is especially critical, as these wells are all candidates for multistage fracturing operations in the completion phase.

The successful liner job in these wells face several challenges: placement of 4½ inch liner in 6 inch hole, hole conditioning, cement placement and ECD challenges due to low fracture gradient limit.

An integrated Basis of Design was developed to mitigate the challenges. This includes The placement of liners with computer aided torque & drag analysis,Rotation of liner during hole conditioning & cementing at highest possible rpm within acceptable torque limits,Fine tune fluid properties with computer aided simulator to achieve sufficient cement coverage around the liner (displacement efficiency).

The liner hanger system in this case study has an advanced running tool to facilitate the required rotating capability. The liner hanger also incorporates a contingency tertiary setting mechanism for liner expansion due to the challenging down hole condition. The expandable liner hanger is an integrated hanger packer system. Elastomeric elements are bonded on to the hanger body itself. As the hanger body is expanded, the elastomeric elements are compressed in the annular space, which provides primary annular isolation at liner top.

This case study also examined the impact of liner rotation on displacement efficiency of the cement slurry with computer aided Finite Element Analysis. The results give engineers a better understanding of the relationship between rpm and displacement efficiency of the cement slurry.

The technology and the practices established from this case study have become the standard operating procedures for liner cementing jobs in subsequent ERD wells.
Systems Of Action - A Blue Print For Real-time Decision Support Systems
Authors: Wesenberg Harald , Landre Einar
Published: September 2015

Capability stacks have proven to be a useful tool for organizing and reasoning about business capabilities. At Statoil we have used it for our Integrated Operations initiatives, as well as for other initiatives such as Integrated Environmental Monitoring. In this paper we introduce and illustrate the concept of capabilities stacks, and describe how the concepts of such a capability stack would be implemented using micro-services and autonomous multi-agent systems supporting a real-time decision support system. The introduction of multi-agents changes the system from a “system of record” (where a human operator is firmly in control and the system provides information for the human operator to make decisions) to a “system of action” (where multi-agents analyze and take action based on available information, and where a human operator has less influence (but remains firmly in control) over the system actions.

The introduction of micro-services and multi-agents provides numerous benefits from a systems engineering perspective. Micro-services allow for the isolation of capabilities in easily definable contexts that interacts with their environment through a set of well-defined interfaces, while multi-agents allow for simplified reasoning around capabilities through the goals and rules of the agents without necessarily knowing all of the implementation details. In turn, this allows for a useful discussion around capabilities, and by stacking these capabilities according to a few design principles we are better able to understand and reason about the total system capabilities within a reasonable timeframe and with reasonable amount of analysis resources.
A Three-Dimensional Thermal Model for Hydraulic Fracturing
Authors: Amini Kaveh , Soliman Mohamed Y. , House Waylon V.
Published: September 2015

Distributed Temperature Sensing (DTS) can provide the wellbore temperature profile during the hydraulic fracturing treatment. This temperature profile is a complex function of many parameters including leakoff coefficient, thermal conductivities of the rock and the injected fluid, minimum stress, porosity, etc. Because of these complexities analytical solutions are not capable of adequately determining the effect of these various parameters on the temperature profile. Moreover, these parameters may vary from one layer to another. Therefore, a three-dimensional temperature model is needed to estimate the fracture parameters by matching the wellbore temperature profile with simulation results.

A three-dimensional temperature model was developed to determine the temperature profile in and around the fracture based on a pseudo three-dimensional (P3D) fracture propagation model. The propagation model, the wellbore thermal model, and the fracture thermal model were solved simultaneously to consider the effect of temperature and pressure on various parameters, such as specific volume. Moreover, the results of the fracture propagation simulation of five cases were compared with the results of full 3D simulators, obtained from literature.

The fracture half-length, fluid efficiency and the net pressure at the entrance of the fracture simulated by this model were in good agreement with the results of full 3D simulation. The minifrac propagation, closure and its temperature were also simulated by this model. The pressure decline curve was predicted by simulator while the effect of temperature and pressure on other variables, such as fracturing fluid density and viscosity, was considered. Additionally, it was observed that the location of optical fiber cable was very important in DTS temperature measurement. Accordingly, a method is provided to consider the effect of the distance of the fiber optics cable from the fracture.

The development of this hydraulic fracturing 3D thermal model is another step for the interpretation of the wellbore thermal profile, measured by the DTS technology during hydraulic fracturing treatment. This model is also capable of being used for more accurate hydraulic fracturing design and analysis.
Nanotechnology Improves Wellbore Strengthening and Minimizes Differential Sticking Problems in Highly Depleted Formation
Authors: Al-Baghli Waleed , Saradhi Vijay , Anas Muhammed , Alherz Ahmad , Rajagopalan Arun , Tobeh Samir , Khatib Faiz , Jadhav Prakash , Yadav Prahlad
Published: September 2015

It is a challenge to drill in highly deviated or horizontal holes across the highly depleted formations. Wellbore instability, differential sticking and mud loss are frequently encountered problems while drilling a depleted reservoir in deep HTHP wells in Kuwait. Long-term production caused formation pressures to be highly depleted, and drilling became more challenging with considerable non-productive time. Therefore, it is necessary to identify a fluid’s solution when other options with casing zone isolation are not viable. Traditionally, oil-based mud (OBM) was used while drilling these formations with limited success.

A customized fluid system was designed to overcome the issue of high overburden pressure in depleted formations targeting effective bridging, minimizing pore pressure transmission and strengthening the wellbore. A nano-size deformable synthetic polymer, along with sized calcium carbonate and graphite, was identified to effectively plug the pore throats and minimized the fluid invasion, which was confirmed by particle plugging tests.

A well section was identified to comingle the highly depleted and pressurized formations. This was the first attempt on a high-angle well with deep drilling operations in Kuwait and was performed to facilitate the successful drilling of the reservoir. Traditional OBM was converted to a customized fluid system using a nano-size polymer and sized bridging additives based on proprietary software selection and series of laboratory tests. Drilling, coring and logging were successfully performed for the first time in the commingle section without incident. There was no wellbore instability or differential sticking tendencies, less torque and drag, as well as enhanced wellbore cleaning in the high-angle sections.

This paper also presents the some of the successful applications of the nano-size deformable polymer in OBM to drill highly depleted formations in HTHP wells managing upto 3500 psi overbalalnceacross highly permeable formations.
Numerical Analysis for Promoting Uniform Development of Simultaneous Multiple Fracture Propagation in Horizontal Wells
Authors: Wu Kan , Olson Jon , Balhoff Matthew T. , Yu Wei
Published: September 2015

Multi-stage hydraulic fracturing together with horizontal drilling plays an important role in the economic development of unconventional reservoirs. However, according to field analysis of stimulation effectiveness, only a small percentage of perforation clusters contribute to most of the well production. One reason for this low effectiveness is that multiple fractures do not take the same amount of fluid and proppant due to fracture interaction (i.e., stress shadow effects). Unfortunately, how best to minimize the negative effects of stress shadowing is still poorly understood in the petroleum industry. In this paper, we analyzed this problem in order to promote more uniform fracture growth using our complex hydraulic fracture development model.

We employed our fracture propagation model that couples rock deformation and fluid flow in the fracture and horizontal wellbore. Partitioning of flow rate between multiple fractures was calculated by analogizing to the electric circuit network. Fracture development is dominated by flow rate distribution, which is controlled by flow resistance within the fractures. For simultaneous multiple fracture propagation, non-uniform flow rate distribution is induced because stress shadow effects exert additional flow resistance on the interior fractures. To balance the extra resistance introduced by the effects, we investigated two adjustment approaches to promote uniform fracture development. The first approach was to adjust perforation number or diameter to increase flow resistance entering the exterior fractures. The second was to mitigate stress shadow effects through managing non-uniform fracture spacing. We found that decreasing perforation diameter or numbers of the exterior fractures can divert fluid into the interior fractures and promote even fracture growth. Stress shadow effects can be mitigated by moving the two interior fractures away from each other and toward the exterior fractures. The key mechanism is to maintain even flow resistance within each fracture and facilitate fractures to obtain the same amount of injection fluid. Furthermore, flow resistance is affected by near-wellbore fracture tortuosity, natural fractures, and stress heterogeneity in the reservoirs. These factors might also be effectively controlled by adding extra flow resistance to pass perforations, provided that this extra resistance is larger than the extra resistance introduced by the factors.

This work analyzes the problem of uneven development of multiple fractures along the horizontal wellbore and provides new insights into how to control simultaneous multiple fracture propagation. It offers potential approaches for engineers to apply in the field to optimize hydraulic fracturing treatment design and thereby maximize well production cost-effectively.
Structuring an Integrative Approach for Field Development Planning Using Artificial Intelligence and its Application to an Offshore Oilfield
Authors: Ketineni Sarath Pavan , Ertekin Turgay , Anbarci Kemal , Sneed Tom
Published: September 2015

In early stages of reservoir depletion, it is often a challenging task to accurately determine reservoir properties that are representative of the actual field. Due to different scales of data obtained from various sources like seismic data, well logs, cores, and production data, there is a lot of uncertainty in solving the inverse problem of estimating formation rock and fluid properties from the field data. Hard-computing protocols like reservoir simulation are time and labor intensive. The objective of the current study is to develop a reservoir characterization tool using a novel approach of correlating seismic attributes with well logs and production data using artificial intelligence approach. The tool will enable construction of spatial oil maps at different times revealing sweet spots and aid in optimized field development planning.

A workflow is developed for devising a comprehensive reservoir characterization tool based on artificial expert systems. A case study of an offshore deep-water asset is used in demonstrating the tenets of the workflow. The reservoir under consideration is highly heterogeneous in terms of property distribution and is believed to be highly channelized. The ANN based tool assists in identifying sweet spots by predicting optimal well location/completion parameters and production profiles.

The multilayer feedforward back-propagation based neural network tool developed is able to capture the correlations that exist amongst seismic data, well logs, completion data, and production data. Well logs are correlated to seismic attributes and geometric location of wells with an average testing (blind test) error of less than 20%. Having correlated seismic data with well logs, synthetic well logs are generated for the entire area of seismic coverage. Synthetic well logs combined with seismic data are able to correlate well with the production within 21% error. The tool developed enables users to predict entire well log suites for even a directional well of user defined configuration through a graphic user interface in a short period of time (typically less than a minute).

This methodology uses a unique way of computing seismic attributes following a horizontal well path and correlating them with the suite of well logs. Incorporation of interference effect from neighboring producers and injectors, schedule of production and functional links based on geographic location has made the production performance module robust and reliable. The workflow enables generation of oil production forecast maps through production performance network. NPV (net present value) calculations integrated with production forecasts is used in identifying the potential infill well locations. The results discussed in the paper showcase the robust nature of the methodology.
Advanced Data-Driven Performance Analysis For Mature Waterfloods
Authors: Mijnarends Runo , Frolov Andrey , Grishko Fedor , Kryanev Svyatoslav , Mikhaylenko Egor , Nizamutdinov Eduard , Plokhotnichenko Oleg , Irina Surovets , Ulyanov Egor , Volokitin Yakov , Gladkov Andrey , Belyanushkina Maria , Lvov Anton
Published: September 2015

We present a novel, data-driven approach to integrated well/reservoir performance analysis and opportunity identification for mid- to late-life pattern waterfloods.

The Salym group of oilfields is located onshore in Western Siberia, Russia's prime oil producing province, and is operated by Salym Petroleum Development (SPD), a 50-50 joint venture between Shell and Gazprom Neft. The main productive formation, comprising strongly layered, deltaic/fluviatile sandstones, has been developed as a pattern waterflood, with over 950 deviated wells drilled since 2004. Overall watercut is currently around 82% and with oil production declining at 6-7% year on year, waterflood management is an absolute strategic priority.

The operator has responded to this challenge by investing heavily in waterflood management and performance evaluation. Particularly, a dedicated effort was made to develop the company's enterprise information architecture and create a purpose-built online waterflood management tool (WMT). All Salym geological, completion, production and well status data is automatically quality-checked, stored and updated in an integrated waterflood database and made accessible through the WMT. The WMT provides a wide range of functionality for data visualization, performance diagnostics and analysis. Furthermore, it is coupled to a full-field surveillance simulation model, which auto-updates with new oilfield data as it becomes available and outputs streamlines, well allocation factors, maps of remaining oil distribution and pattern- and block-level calculated properties.

These technologies have enabled the development and implementation of a structured methodology for waterflood performance evaluation that involves systematic assessment of blocks of 20-50 wells in the form of an Annual Field Review (AFR) followed by a series of deep-dive Integrated Block Reviews (IBRs). During the AFR, each block is assessed against a set of KPIs and scored and prioritised in terms of its health status and projected recovery shortfall. Based on this prioritisation, blocks are scheduled for review in an IBR during the course of the year. The IBRs focus on individual wells, patterns and reservoirs and during the reviews concrete well, reservoir and facilities management (WRFM) opportunities are identified to address performance gaps and sweep or accelerate remaining oil. These opportunities are captured in an online opportunity register coupled to an online database for workover strategy preparation.

The framework of technologies and processes presented in this paper was instrumental in planning and executing over 260 WRFM activities (not including simple pump change-outs) across the Salym fields in 2014, delivering in excess of 3.2 Mln bbls of in-year oil production.
Acoustic Signature of Flow From a Fractured Wellbore
Authors: Chen K. , Zhu D. , Hill A. D.
Published: September 2015

Distributed acoustic sensing (DAS) technology is emerging in the area of hydraulic fracture monitoring and diagnosis. The number of applications using DAS technology has been growing significantly from determining flow distribution to detecting multiphase flow. Some of the current DAS technology in the hydraulic fracture diagnosis area utilizes sound intensity on the spectrogram plot of the acoustic measurements to qualitatively analyze fracture initiation.

In this paper, we present the results of our simulated fracture, perforation tunnel, and wellbore system experiments measured by a distributed hydrophone array in both the time and frequency domain. The experiments were conducted on a wellbore with two fracture cells. The wellbore can be either horizontal or vertical. The customized fracture cells with long and thin geometry were connected through a perforation tunnel to a 5-inch ID wellbore. In the horizontal wellbore setup, fluid was injected through the fracture cells and perforation tunnels to the wellbore. The experiments used hydrophone and microphone array to measure the acoustic signals from each fracture. Relative locations of the hydrophones to the fractures and the rate difference from the two fractures are the main parameters examined during the experiments. The measured acoustic data were analyzed using DSP techniques to characterize the location and rate differences. We first studied how the fracture and perforation tunnel alone affect the acoustic signature of the flow from the fracture to the wellbore; this study allows extraction of individual fracture and perforation related information from the overall measured DAS data from the combined system. We then analyzed how multiple perforation tunnels and different flow distributions changed the acoustic frequency spectrum. Additional parameters affecting acoustic behavior were investigated including single phase liquid, multiphase fluid, and liquid column. The digital signal processing (DSP) algorithm is explained in the paper. A correlation based on experimental observation was developed to quantitatively estimate the flow rate and flow distribution of multiple perforation tunnels from acoustic signals measured in the wellbore.