Field development strategies in unconventional shale reservoirs have increased in intensity over the last few decades. Completion design and well spacing have been key focus variables in the incremental design process. With this wide range of design and development strategies, assets across different basins might end up with wells from a variety of design generations. This could make type curve creation even more complicated as it does not account for impact of hydrocarbon drainage in an area by the older (parent) well on the newer (child) wells. The present paper tackles this issue by addressing type curve development by including date dependent spacing variables to account for the dynamism of field development strategies over the years.
The present paper analyzes the impact of well spacing on type curve development in an asset. Type curve generation is a critical component in evaluation and subsequent planning so de-risking this step is very valuable. A lot of the analysis done in recent years is by considering well spacing as a static variable. The present analysis looks at spacing as a dynamic variable instead to account for time-series based variations. The spacing in the estimation process is also a 3-D spacing algorithm which identifies multiple points along the lateral section of the wellbore for a true evaluation of pressure transient propagation.
The present analysis showed the impact of date dependent well spacing on type curve development. The underestimation of well spacing in well-developed acreages was brought to attention as spacing mean deviations of upto 0.7 Standard Deviation were found between current well speacing and date-dependent well spacing scenarios analyzed. These deviations led to the type curves having upto a 40% EUR differential between estimation processes, with PV10 differentials higher than 100% in some cases. While the degree of impact of time series well spacing varied across the assets evaluated, quantifying the risk in type curve development and subsequent EUR estimation were key conclusions from the analysis.
The present paper presents a novel approach in tackling type curve development for parent and child wells observed across different basins. The paper provides guidelines on creating highly accurate type curves and highlights errors that may arise due to high well density and inter-well interaction by conducting the analysis in the high well density Middle Bakken formation.
Pre-set or off-depth composite plugs can cause significant non-productive time for a well operator. In the past, fracturing operations using a composite frac or bridge plug that has been pre-set or set off depth required a coiled tubing unit or workover rig to drill the plug out. Then, the well operator could resume the fracturing job or access the wellbore below the plug. However, as this paper demonstrates, composite plug milling via wireline using a tractor and a tractor-based milling tool is a faster, safer, and more cost-effective solution.
In a shale well located in the northern panhandle of West Virginia, a composite frac plug was set off- depth. Prior to mobilizing the tractor-based solution to location, the operator attempted pumping approximately 60,000 pounds of sand to sand-cut the off-depth frac plug out of the well. The sand cutting, though, did not work because perforations above the frac plug took the sand. Other tubing-based solutions required more mobilization time and complex logistics for rigging down and/or moving equipment on location. Therefore, the operator chose a wireline-based method for ease of operation, reduced HSE risk, and cost savings.
The tractor took 50 minutes to drive down 1718 ft in the lateral to the plug. The milling tool milled the top slips on the frac plug in approximately nine hours, and the tractor then pushed the plug 222 ft downhole on top of the previous frac plug. The total time rigged up on the well was 14 hours, and the total time on location was 18 hours. Although this wireline-based plug-milling method takes several hours to mill a plug, the rig-up and execution is simpler than conventional methods, and associated HSE risks on the wellsite are greatly reduced.
The ability to effectively release plugs via wireline provides well operators with another option to complete their objectives, especially when tubing-based methods often take many days or weeks to mobilize at substantial cost to operators.
Gan, Thomas (Shell Trinidad & Tobago Ltd) | Kumar, Ashok (Shell Trinidad & Tobago Ltd) | Ehiwario, Michael (Shell Exploration & Production Company) | Zhang, Barry (Quantico Energy Solutions) | Sembroski, Charles (Quantico Energy Solutions) | de Jesus, Orlando (Quantico Energy Solutions) | Hoffmann, Olivier (Quantico Energy Solutions) | Metwally, Yasser (Quantico Energy Solutions)
Borehole-log data acquisition accounts for a significant proportion of exploration, appraisal and field development costs. As part of Shell technical competitive scoping, there is an ambition to increase formation evaluation value of information by leveraging drilling and mudlogging data, which traditionally often used in petrophysical or reservoir modelling workflow.
Often data acquisition and formation evaluation for the shallow hole sections (or overburden) are incomplete. Logging-while-drilling (LWD) and/or wireline log data coverage is restricted to mostly GR, RES and mud log information and the quality of the logs varied depending on the vendor companies or year of the acquisition. In addition, reservoir characterization logs typically covered only the final few thousand feet of the wellbore thus preventing a full quantitative petrophysical, geomechanical, geological correlation and geophysical modelling, which caused limited understanding of overburden sections in the drilled locations and geohazards risls assessment.
Use of neural networks (NN) to predict logs is a well-known in Petrophysic discipline and has often used technology since more than last 10 years. However, the NN model seldon utilized the drilling and mudlogging data (due to lack of calibration and inconsistency) and up until now the industry usually used to predict a synthetic log or fill gaps in a log. With the collaboration between Shell and Quantico, the project team develops a plug-in based on a novel artificial intelligence (AI) logs workflow using neural-network to generate synthetic/AI logs from offset wells logs data, drilling and mudlogging data. The AI logs workflow is trialled in Shell Trinidad & Tobago and Gulf of Mexicooffshore fields.
The results of this study indicate the neural network model provides data comparable to that from conventional logging tools over the study area. When comparing the resulting synthetic logs with measured logs, the range of variance is within the expected variance of repeat runs of a conventional logging tool. Cross plots of synthetic versus measured logs indicate a high density of points centralized about the one-to-one line, indicating a robust model with no systematic biases. The QLog approach provides several potential benefits. These include a common framework for producing DTC, DTS, NEU and RHOB logs in one pass from a standard set of drilling, LWD and survey parameters. Since this framework ties together drilling, formation evaluation and geophysical data, the artificial intelligence enhances and possibly enables other petrophysical/QI/rock property analysis that including seismic inversion, high resolution logs, log QC/editing, real-time LWD, drilling optimization and others.
Ghanavati, Mohsen (Global New Petro Tec Corp.) | Volkov, Maxim (TGT Oilfield Services) | Nagimov, Vener (TGT Oilfield Services) | Ali Mohammadi, Hamzeh (University of Calgary, Global New Petro Tec Corp.)
Production casings of Cyclic Steam Stimulation (CCS) or steam-assisted gravity drainage wells are exposed to significant temperature variations which in many cases resulted in casing breaks in the weakest part which are typically connection joints. The paper focuses on the new downhole logging approach, in monitoring and detecting production casing connection breaks through tubing without requirement for tubing retrieval.
The metal well barriers can be assessed by utilizing electromagnetic (EM) pulse defectoscopy. This is done by running multiple coaxial sensors downhole in tandem. Each sensor generates EM pulse and then records EM decay from surrounding metal tubes. Modeling of recorded EM decay enables precise assessment of metal loss or metal gain in up to four concentric barriers. However, the tool had never been used previously to detect minor defect features as casing breaks through the tubing. To identify casing breaks several yard and field tests have been conducted and new methodologies were developed. The last one included the recognition of specific patterns of raw EM responses, analysis of hole sensors and utilization of data from all coaxial sensors utilized during the downhole survey.
The new approach including downhole EM pulse tools and new data analysis have been implemented to detect casing connection breaks in over a hundred Cyclic Steam Stimulation (CCS) and SteamAssisted Gravity Drainage (SAGD) wells. The paper demonstrates the testing of the application feasibility in a comprehensive yard test and extends to real field examples. All detected breaks were confirmed after tubing removal and were successfully repaired. Paper highlights detection challenges due to different casing connection break types: minor breaks, partial breaks (contrary to fully circumferential), and casing breaks aligned with tubing connections. The technology has helped Operators to fulfil the objectives of connection break detection without tubing removal through a non-intrusive, safe, quick and economical approach.
Today, CSS and SAGD Operators should confirm casing integrity repeatedly prior to each subsequent steam cycle through the time and resource consuming approach of tubing removal and checking the casing integrity mechanically. Utilizing through tubing electromagnetic diagnostics, enables Operators to pick up multiple casing connection breaks in a single run without tubing retrieval.
It is well known that geophysics, particularly the
This paper reviews existing analysis of well integrity related regulation in upstream unconventional oil and gas projects and proposes a methodology to enhance such regulation in the future. This paper has compiled findings from a number of peer-reviewed sources assessing regulatory systems across a number of jurisdictions. These findings were based around four key questions that this paper has assessed (1) what is the overall assessment of current regulatory systems; (2) where to-date are the key areas that current research have focused on; (3) what are the key strengths identified in current research; and (4) what are the key gaps in current research?
This paper demonstrates that the body of work provides a wide array of assessments and conclusions. Whilst some are quite explicit in their judgment of a particular system’s effectiveness, many refrain from making a holistic assessment in a particular jurisdiction. Much of the research involves the application of prisms, such as environmental risks or local government jurisprudence. Along with these prisms, a number of common aspects of research are identified that strengthen the analyses, such as the use of ‘as drilled’ data and the use of relevant data samples. Some research gaps remain despite these strengths.
The majority of previous researchers can identify some degree of ineffectiveness in various regulatory regimes. Further, a number of gaps exist as a result of regulatory systems being incomplete or inadequate, potentially masking other inadequacies. To address these gaps, this paper proposes a methodology to improve and clarify knowledge and practical recommendations to improve the effectiveness of assurance activities by both regulatory agencies and operators. Specifically, this methodology focuses on a typological assessment of written rules in a number of jurisdictions. As an example, we present an ‘as built’ dataset to assess compliance with rules and identify means of assurance. This methodology proposes surveying of regulatory agencies and operators to validate the assertion that gaps can be identified and corrected and provide more insight into how regulatory systems function and the systematic causes of gaps.
The need for monitoring individual well production in unconventional fields is rising. The drivers are primarily related to accurate reporting for production allocation between wells. The main driver in North American operations for a meter-per-well flow rate monitoring has been the need for accurate per well production accounting due to the complexity of the land-owner interest.
There are additional benefits from the monitoring of early decline and determination of the transient evolution of the reverse productivity index (RPI) to evaluate the well performance. The availability of long-term rate transient data supports decline analysis and rate transient analysis, leading to better understanding of the estimated ultimate recovery (EUR), which may drive the selection of infill drilling locations. Finally, the identification of interference between flowing wells can help mitigate the issues of parent/child wells.
A specific case in the Eagle Ford is the systematic deployment of full gamma-spectroscopy multiphase flowmeters at well pads. This intelligent pad architecture consists of one multiphase flowmeter per well and a production manifold that enables commingling of the production to a single flowline connected to the inlet manifold of the production facility.
The rationale of the decision for the installation of such solution in lieu of a metering separator per well is based on the evaluation of the impact of this technology on capex and opex reductions.
Several lessons learned are provided. They include a discussion of the change management issues related to the installation of the meters, the modifications necessary to the production facility at the receiving side, and the data management and data analytics that were enabled from the gathering of systematic, continuous, and high-resolution measurements.
The impact of the installation of the meters in the field is noticeable and quantifiable. with several prior wells used as a benchmark. The effects are not limited to cost reduction, but also lead to an increase in production related to the release of operational crews from daily well testing tasks that used to be necessary. The data quality and coverage are also increased.
A few suggestions are made concerning optimization of the deployment and use of remote monitoring options for enhanced efficiency. Automated data workflows are also discussed.
The reduction of HSE risks through a better management of field operators is also assessed.
Cap rock integrity in Alberta's Oil Sands has gained increasing industry prominence over the years. A competent cap rock seal is a key mandate to subsurface containment assurance in thermal operations such as Steam Assisted Gravity Drainage (SAGD). Containment loss incidents in the past decade present substantial insights into regulating thermal development prospects as well as defining and benchmarking the industry practices in Alberta. Cap rock characterization and its response to high pressure and temperature in SAGD greatly influences the reservoir management strategy adopted by the operators. Constraints on the Maximum Operating Pressure (MOP) and safety factors are generally premised on tensile or shear cap rock failure probabilities.
This work integrates and analyzes key industry data from subsurface disciplines of geology, geophysics, geomechanics and reservoir engineering in characterizing regional Clearwater and Wabiskaw shale cap rocks in the Athabasca basin. A comprehensive analysis was conducted on sixteen (16) commercial oil sands projects and incident reports. Applications, reports and Supplemental Information Requests (SIRs) submitted to the Alberta Energy Regulator's (AER) published data and relevant literature was consulted to generate regional interpretations of the cap rock properties and industry approaches. A regional database of key properties including In-situ stresses, horizontal stress anisotropies, pore pressure gradients, and rock mechanical properties was compiled. In addition, regional failure modeling practices including numerical modeling assumptions, coupling, initial and boundary conditions and failure criteria are studied. Finally, common reservoir and cap rock monitoring techniques are explored.
Major conclusions from this study include regional interpretations of various risk factors affecting cap rock integrity in Oil Sands. Inferences from pooled industry data is used to generate a holistic interpretation of the Wabiskaw and Clearwater cap rocks. Intrinsic risk factors embedded in commonly practiced cap rock evaluation techniques, modeling and surveillance techniques in SAGD operations are identified alongside containment assurance programs commonly adopted by industry stakeholders. A summary of findings is provided at the end of this study for Operators to consider advancing their view on subsurface containment risk management.
The oil & gas industry uses production forecasts to make a number of decisions as mundane as whether to change the choke setting on a well, or as significant as whether to develop a field. As these forecasts are being used to develop cashflow predictions and value and decision metrics such as Net Present Value and Internal Rate of Return, their quality is essential for making good decision. Thus, forecasting skills are important for value creation and we should keep track of whether production forecasts are accurate and free from bias.
In this paper we compare probabilistic production forecasts at the time of the development FID with the actual annual production to assess whether the forecasts are biased; i.e., either optimistic, overconfident, or both.
While biases in time and cost estimates in the exploration & production industry are well documented, probabilistic production forecasts have yet to be the focus of a major study. The main reason for this is that production forecasts for exploration & production development projects are not publicly available. Without access to such estimates, the quality of the forecasts cannot be evaluated.
Drawing on the Norwegian Petroleum Directorates (NPD) extensive database, annual production forecasts, given at time of project sanction (FID), for 56 fields in the 1995 – 2017 period, have been compared with actual annual production from the same fields. The NPD guidelines specify that the operators should report the annual mean and P10/90-percentiles for the projected life of the field at the time of the FID; that is, the forecasts should be probabilistic. The actual annual production from the fields was statistically compared with the forecast to investigate if the forecasts were biased and to assess the financial impact of such biases.
This paper presents the results from the first public study of the quality of probabilistic production forecasts. The main conclusions are that production forecasts that are being used at the FID for E&P development projects are both optimistic and overconfident. As production forecasts form the basis for the main investment decision in the life of a field, biased forecasts will lead to poor decisions and to loss of value.
During the last five years, the use of permanent downhole gauges has proliferated in the industry. The availability of true bottomhole pressure (BHP) is imperative in validating/improving reservoir models. Similarly to the extrapolation of BHP from surface readings, the use of BHP to extrapolate formation pressure may lead to significant errors in reservoir models that do not provide operators with the competitive edge needed in the current market. Consequently, there is a drive to monitor formation pressure in-situ by placing pressure and temperature gauges in direct contact with the formation.
In recent years, operators have been drilling larger holes, deploying gauge systems on the exterior of the casing, and cementing the gauge systems in place for multiple purposes. In artificial lift applications, cemented gauge systems have helped operators to avoid costs of decompleting and redeploying gauge systems on tubing whenever the electric submersible pumps (ESP) must be serviced, or perhaps whenever operators want to convert an observation well to a producing well.
In unconventional plays, technologies involving quartz pressure and temperature gauges, oriented perforating, and well conditioning practices can enable operators to deploy multiple real-time downhole pressure and temperature gauges on casing across long horizontal sections of a wellbore. This, in turn, can provide valuable production data with which to understand cluster production performance, cross-well communication, fracture azimuth, well spacing, and stage-length production implications.
Cemented gauges enable operators to understand pressure dynamics in the overburden, cap rock, or reservoir sections. The permanently installed, casing-deployed gauges connect to the surface through cable or through deployment of wireless inductive coupling technology.