Nath, Fatick (University of Louisiana at Lafayette) | Salvati, Peter E. (University of Louisiana at Lafayette) | Mokhtari, Mehdi (University of Louisiana at Lafayette) | Seibi, Abdennour (University of Louisiana at Lafayette) | Hayatdavoudi, Asadollah (University of Louisiana at Lafayette)
Understanding the mechanical behavior (compression, shear, or tension) of rocks plays an important role in wellbore-stability design and hydraulic-fracturing optimization. Among rock mechanical properties, strain is a critical parameter describing rock deformation under stress with respect to its original condition, yet conventional methods for strain measurement have several deficiencies. In this paper, we analyze the application of the optical method digital-image correlation (DIC) to provide detailed information regarding fracture patterns and dynamic strain development under Brazilian testing conditions. The effects of porosity, rock type, lamination, and saturation (freshwater and brine) on indirect tensile strength are also discussed.
To examine the effect of rock type, 60 samples of sandstone (Parker, Nugget, and Berea) and carbonate rocks (Winterset Limestone, Silurian Dolomite, Edwards Brown Carbonate, and Austin Chalk) were tested under dry and saturated conditions with regard to lamination angle in laminated samples. A photogrammetry system was used to monitor the samples in a noncontact manner while conducting the indirect tensile experiment. DIC depends on the photogrammetry system, which helps to visualize and examine rock-fracture patterns from the recorded images of the rock before and after deformation by assessing the strain development in samples.
The experimental results show the following.
This paper presents a methodology for quantifying uncertainty in production forecasts using Logistic Growth Analysis (LGA) and time series modeling. The applicability of the proposed method is tested by history matching production data and providing uncertainty bounds for forecasts from eight Barnett Shale counties.
In the methodology presented, the trend in the production data was determined using two different non-linear regression schemes. Predicted trends were subtracted from the actual production data to generate two sets of stationary residual time series. Time series analysis techniques (Auto Regressive Moving Average models) were thereafter used to model and forecast residuals. These residual forecasts were incorporated with trend forecasts to generate our final 80% CI.
To check reliability of the proposed method, we tested it on 100 gas wells with at least 100 months of available production history. The CIs generated covered true production 84% and 92% of the time when 40 and 60 months of production data were used for history matching respectively. An auto-regressive model of lag 1 was found to best fit residual time series in each case.
The proposed methodology is an efficient way to generate production forecasts and to reliably estimate the uncertainty. The method is computationally inexpensive and easy to implement. The utility of the procedure presented is not limited to gas wells and can be applied to any type of well or group of related wells.
Nath, Fatick (University of Louisiana at Lafayette) | Salvati, Peter E (University of Louisiana at Lafayette) | Mokhtari, Mehdi (University of Louisiana at Lafayette) | Seibi, Abdennour (University of Louisiana at Lafayette) | Hayatdavoudi, Asadollah (University of Louisiana at Lafayette)
Strain is a critical parameter in the calculation of elastic rock properties, yet its conventional methods for strain measurement has several deficinies. In this paper, we analyze the application of optical methods with Digital Image Correlation (DIC) technique to provide detailed information regarding fracture patterns and strain development with time under Brazilian testing condition. The effect of porosity, rock types, lamination, and saturation on tensile strength will be also discussed.
To examine the effect of rock type, 60 samples of sandstone (Parker, Nugget and Berea) and carbonate formations (Winterset limestone, Silurian dolomite, Edward Brown and Austin Chalk) were testedunder dry and saturated conditions and with regard to lamination angle in laminated samples. A Vic-snap photogrammetry system was employed to monitor the samples in non-contact manner while conducting indirect tensile experiment. DIC is based on the photogrammetry system, which helps to visualize and examine rock fracture pattern from the recorded images of the rock before and after deformation by assessing the strain development in samples.
The experimental results show that - (1) average tensile strength declines while increasing porosity for homogeneous, laminated, and heterogeneous rock specimens. (2) lower tensile strengths are observed in carbonate rock samples compared to the sandstones except Silurian dolomite; (3) saturation reduces the rock strengths, for isotropic samples, highest 28% decline in strength (Berea sandstone) observed; whereas, a larger decrease (65%) was observed in fully heterogeneous Edwards Brown carbonate samples; (4) increase of lamination angle (from 0° to 90°) impacts the tensile strength, average tensile strength was observed for Parker and Nugget sandstone greater in perpendicular to the lamination (9 = 90°) direction compare to that of parallel (9 = 0°); (5) fracture patterns examined for homogeneous rocks are almost centrally propagated and relatively linear; whereas, three different fracture patterns (central fracture, layer activation and non-central or mixed mode) investigated for laminated and heterogeneous samples; (6) Finally, DIC results illustrated the fracture initiation and propagation with consistent strain mapping. The homogeneous samples produced a uniform fracture strain until the diametrical split where for the laminated samples were influenced by planes of weakness, and fully heterogeneous anisotropic rocks produced winding and erratic fractures.
This case study describes the motivation and execution of a large 3D surface seismic survey recently conducted over 4,000km2 in the Carnarvon Basin offshore Australia. This survey was the first use of an innovative towed streamer technology in Australasia that enables the collection of broadband, un-aliased isometrically sampled wavefields.
Woodside Energy Ltd (Woodside) operates the North West Shelf gas producing assets that are located on the Rankin Platform, Parker Terrace, Kendrew Trough and also oil fields of the Madeline Trend. Certain areas in the vintage 3D surveys are characterized by poor seismic data quality producing uncertainty in reservoir management and potential prospectivity. In 2012 the North West Shelf (NWS) Project participants held a technical workshop to determine a strategy to maximize the productive life of this acreage and to extend the production from the Karratha gas plant. A key outcome of the workshop was the need for new 3D seismic data of a quality suitable for appraisal, development and exploration activities over the next decade. This resulted in the decision in late 2013 to acquire the “Fortuna 3D” (Fortuna) seismic survey, covering over 4,000km2 (Figure 1). The resulting seismic image is intended to enable the NWS joint venture to explore and develop this core asset with greater confidence.
Fortuna is the first survey in Australia to use a new multi-sensor towed streamer technology. This streamer includes both finely spaced hydrophones and accelerometers embedded in the cable. These streamers digitally measure not only the scalar pressure wave with finely spaced hydrophones as in conventional systems, but also use accelerometers to measure the directional particle acceleration of the seismic wave in both the vertical (Az) and cross-cable (Ay) directions. These additional measurements when carefully combined provide a broadband frequency signal that allows the reconstruction of the seismic wavefield with fine spatial sampling to improve both noise attenuation and subsequently the subsurface image. This “three component” streamer technology was augmented with other innovations including multilevel seismic sources, integrated real time navigation and streamer steering along with massive computing resources to facilitate data conditioning and initial signal processing on the vessel.
As shown in the map in Figure 1, the Fortuna survey presented several operational challenges including concurrent oilfield operations, working around infrastructure and other vessels, plus environmental challenges associated with strong tides and unpredictable currents. These issues required careful forecasting and planning due to the dynamic nature of this operational environment.
A new low-concentration, low-viscosity delayed-crosslink polymer gel system was developed for water shutoff in small aperture features in higher temperature oil and gas reservoirs. The gel employs hydrolyzed polyacrylamide (HPAM) and Polyethyleneimine (PEI) crosslinker. Addition of 2-Acrylamido-2-methylpropane sulfonic acid (AMPS) as a crosslink delay agent increases the gelation time by several days at temperatures well above 100 °C. Resulting gels were significantly stronger than those prepared with chromium acetate crosslinker at the same polymer concentrations. The HPAM-PEI-AMPS system consists of inexpensive components which are widely used in the oilfield. The system was studied for effects of concentration of polymer and crosslinker, PEI:AMPS ratio, pH and cation concentration on gelation time and gel strength. Gelant solutions prepared with high molecular weight HPAM exhibit a longer delay in gelation at temperatures well above 100 °C. The ability to form strong gel at lower polymer concentrations, with a considerable delay in gelation time, offers the opportunity to extend application of flowing gels to water shutoff in fractured reservoirs where extrusion pressures are too great for more conventional flowing gels that are partially crosslinked during placement. The system is especially promising for deeper, hotter formations where rapid pressure buildup or gel instability prevents the use of current flowing gel systems. The gelant can be pumped at low pressures due to the low concentration of polymer and the delayed gelation to effectively seal problem water zones thereby reducing operational costs and increasing recovery. By impeding water production, the gel system developed here can be used to delay excess water influx and thus premature abandonment (or installation of expensive lift equipment), thereby extending the life and reserves of unconventional oil and gas wells.
It is believed by many in the Health and Safety sector that up to 80% of work-related accidents are down to employee behavior or the human factor, in the form of acts or omissions. Such behavior as this can lead to many small-factors coming together to produce a negative outcome or accident. There are many reasons why employees engage in ‘at-risk' behavior at work including but not limited to: cutting corners to save time, ergonomic factors, accepted practices, reinforcement of at-risk behavior by the actions of supervisors, misunderstanding at-risk behavior and instinctive risk-tasking behavior.
The emphasis of the behavior based approach to safety is on employees' behavior. Through influencing behavior, this system can reduce injury rates. The behavioral based approach to safety is focused exclusively on the observable, measurable behaviors critical to safety at a particular facility. This is a task orientated view of behavior, and it treats safe behavior as a critical work-related skill. It should not be confused with inspections and audits of the workplace for unsafe conditions.
Behavioral safety is part of a natural progression of safety management from highly prescriptive approaches, through the engineered or procedural systems which most progressive companies have long since established, to a system which recognizes workers as mature human beings with a genuine interest in their own well-being, who contribute best when they can see that they themselves can have an influence on their own safety. To achieve this transition is to change the culture of the work group involved, so this approach will not provide instantaneous results. Human behavior is often categorized as reflex/automatic, intended and habitual, and this is what we need to change or adapt.
This paper will look at best practice and how employers and employees can influence the human factor, by examining how we can reinforce safe behaviors or good habits and removing or reducing unsafe ones. The key to which lies in first indentifying those behaviors which are critical to safety and in subsequent regular observations to monitor them.
Behavioral Safety - Human Factors
It is believed by many in the Health and Safety sector that up to 80% of work-related accidents are down to employee behavior or the human factor, in the form of acts or omissions. Such behavior as this can lead to many small-factors coming together to produce a negative outcome or accident. There are many reasons why employees engage in ‘at-risk' behavior at work including but not limited to: cutting corners to save time, ergonomic factors, accepted practices, reinforcement of at-risk behavior by the actions of supervisors, misunderstanding at-risk behavior and instinctive risk-taking behavior.
The emphasis of this approach to safety is on employees' behavior. Through influencing behavior, this approach can reduce injury rates. The behavioral based approach to safety is focused exclusively on the observable, measurable behaviors critical to safety at a particular facility. This is a task orientated view of behavior, and it treats safe behavior as a critical work-related skill. It should not be confused with inspections and audits of the workplace for unsafe conditions.
In 2007, the Barnett Shale in the Fort Worth basin of Texas produced 1.1 trillion cubic feet (Tcf) gas and ranked second in U.S gas production. Despite its importance, variations of reservoir properties and their effects on well performances have not been assessed. Therefore, we evaluated production statistics for the 5 Barnett production regions, and to assess controls on Barnett Shale production rates and fluid composition, we related production to completion method, reservoir interval completed, reservoir properties and geologic setting.
In all five production regions, horizontal wells produce approximately twice as much oil and gas as do vertical wells. First Year gas production of horizontal wells (P50) ranges from 30 to 350 MMcf. First Year oil production from horizontal wells ranges from 0 to 8,000 bbl. There are positive relations between the reservoir units perforated and production rates and volume, but there are no obvious monotonic relations between perforation interval thickness and Peak Monthly or First Year oil or gas production. After filtering the wells by the number of fracture and acid treatments, we did not observe any relationships between production and perforated interval thickness.
On the basis of petrophysical characteristics from 800 well logs, we divided the Barnett Shale into 4 reservoir units that are significant to engineering decisions and reservoir performance. The most productive wells are perforated in Reservoir Units 2, 3 and 4, inclusive. Reservoir Unit 1 is a shaly interval that has a hot gamma ray response and is rarely perforated. Reservoir Unit 2 is laminated, siliceous mudstone and marly carbonate zone. Reservoir Unit 3, the most commonly perforated Barnett reservoir unit, is composed of multiple, stacked, thin, upward coarsening sequences of brittle carbonate and siliceous units interbedded with ductile shales. Reservoir Unit 4, the upper Barnett Shale, is composed dominantly of shale interbedded with upward coarsening, laterally persistent carbonate and siliceous units, similar to Reservoir Unit 3.
This research should provide operators with a better understanding of Barnett Shale geologic and reservoir properties and assist with optimizing development strategies and gas recovery. The results may be applicable to other developing shale gas plays.
A Barnett Shale water production dataset from approximately 11,000 completions was analyzed using conventional statistical techniques. Additionally a water-hydrocarbon ratio and first derivative diagnostic plot technique developed elsewhere for conventional reservoirs was extended to analyze Barnett Shale water production mechanisms. In order to determine hidden structure in well and production data, self-organizing maps and the k-means algorithm were used to identify clusters in data. A competitive learning based network was used to predict the potential for continuous water production from a new well for and a feed-forward neural network was used to predict average water production for wells drilled in Denton and Parker Counties of the Barnett Shale.
Using conventional techniques, we conclude that for wells of the same completion type, location is more important than time of completion or hydraulic fracturing strategy. Liquid loading has potential to affect vertical more than horizontal wells. Different features were observed in the spreadsheet diagnostic plots for wells in the Barnett Shale; and we make a subjective interpretation of these features. We find that 15% of the horizontal and vertical wells drilled in Denton County have a load water recovery factor greater than unity. Also, 15% / 35% of the horizontal / vertical wells drilled in Parker County have a load recovery factor of greater than unity.
The use of both self organizing maps and the k-means algorithm show that the dataset is divided into two main clusters. The physical properties of these clusters are unknown but interpreted to represent wells with high water throughput and those with low water throughput. Expected misclassification error for the competitive learning based tool was approximately 10% for a dataset containing both vertical and horizontal wells. The average prediction error for the neural network tool varied between 10-26%, depending on well type and location.
Results from this work can be utilized to mitigate risk of water problems in new Barnett Shale wells and predict water issues in other shale plays. Engineers are provided a tool to predict potential for water production in new wells. The methodology used to develop this tool can be used to solve similar challenges in new and existing shale plays.