Evaluating Australian unconventional gas: use and misuse of North American analogues

2013 ◽  
Vol 53 (1) ◽  
pp. 37
Author(s):  
Colin Jordan ◽  
Geoff Barker ◽  
Bruce Gunn
Keyword(s):  
North American ◽  
Production Performance ◽  
Successful Implementation ◽  
Tight Gas ◽  
Well Performance ◽  
Unconventional Gas ◽  
Strongly Coupled ◽  
Canning Basin ◽  
Production History ◽  
Intimate Knowledge

Evaluation of Australia’s emerging unconventional gas sector (particularly shale gas, basin centered and tight gas) relies heavily on the use of North American analogues because of the lack of production history in Australian plays. While the use of analogues can be useful, no two shale or tight gas plays are identical so the use of analogues can also lead to significant pitfalls that need to be understood to be avoided. Production performance and recoverable hydrocarbons are strongly coupled to completion technology (far more than a conventional oil or gas project), and the successful implementation of technology requires an intimate knowledge of both reservoir petrophysics and geomechanics, not to mention a well-developed topside supply chain. This paper discusses the application of analogues to major Australian unconventional plays in the Cooper, Canning, and Perth basins, presents a case history from the Canning Basin, and provides guidance on the adjustments needed to ensure realistic predictions of recovery and well performance.

The Use of Rate-Transient-Analysis Modeling To Quantify Uncertainties in Commingled Tight Gas Production-Forecasting and Decline-Analysis Parameters in the Alberta Deep Basin

2014 ◽  
Vol 17 (02) ◽  
pp. 209-219 ◽  
Author(s):  
H.. Luo ◽  
G.F.. F. Mahiya ◽  
S.. Pannett ◽  
P.. Benham
Keyword(s):  
Transient Analysis ◽  
Early Time ◽  
Gas Production ◽  
Tight Gas ◽  
Well Performance ◽  
Deep Basin ◽  
Type Curves ◽  
Production Forecasting ◽  
Rate Transient Analysis ◽  
Production History

Summary The evaluation of expected ultimate recovery (EUR) for tight gas wells has generally relied upon the Arps equation for decline-curve analysis (DCA) as a popular approach. However, it is typical in tight gas reservoirs to have limited production history that has yet to reach boundary-dominated flow because of the low permeability of such systems. Commingled production makes the situation even more complicated with multiboundary behavior. When suitable analogs are not available, rate-transient analysis (RTA) can play an important role to justify DCA assumptions for production forecasting. The Deep-basin East field has been developed with hydraulically fractured vertical wells through commingled production from multiple formations since 2002. To evaluate potential of this field, DCA type curves for various areas were established according to well performance and geological trending. Multiple-segment DCA methodology demonstrated reasonable forecasts, in which one Arps equation is used to describe the rapidly decreasing transient period in early time and another equation is used for boundary-dominated flow. However, a limitation of this approach is the uncertainty of the forecast in the absence of extended production data because the EUR can be sensitive to adjustments in some assumed DCA parameters of the second segment. In this paper, we used RTA to assess reservoir and fracture properties in multiple layers and built RTA-type well models around which uncertainty analyses were performed. The distributions of the model properties were then used in Monte Carlo analysis to forecast production and define uncertainty ranges for EUR and DCA parameters. The resulting forecasts and EUR distribution from RTA modeling generally support the DCA assumptions used for the type curves for corresponding areas of the field. The study also showed how the contribution from the various commingled layers changes with time. The proposed workflow provides a fit-for-purpose way to quantify uncertainties in tight gas production forecasting, especially for cases when production history is limited and field-level numerical simulation is not practicable.

Production Performance Analysis of Volga-Ural Mature Waterflood with PRIME Diagnostic Metrics

2021 ◽  
Author(s):  
Artur Mihailovich Aslanyan ◽  
Bulat Galievich Ganiev ◽  
Azat Abuzarovich Lutfullin ◽  
Ildar Zufarovich Farkhutdinov ◽  
Marat Yurievich Garnyshev ◽  
...  
Keyword(s):  
Performance Analysis ◽  
Production Performance ◽  
Diagnostic Tools ◽  
Practical Case ◽  
Well Performance ◽  
Summary Table ◽  
Main Challenge ◽  
Production History ◽  
Infill Drilling ◽  
Production Trend

Abstract The paper presents a practical case of production performance analysis at one of the mature waterflood oil fields located at the Volga-Ural oil basin with a large number of wells. It is a big challenge to analyse such a large production history and requires a systematic approach. The main production complication is quite common for mature waterflood projects and includes non-uniform sweep, complicated by thief injection and thief water production. The main challenge is to locate the misperforming wells and address their complications. With the particular asset, the conventional single production analysis techniques (oil production trend, watercut trend, reservoir and bottom-hole pressure trend, productivity trend, conventional pressure build-up surveys and production logging) in the vast majority of cases were not capable of qualifying the well performance and assessing of remaining reserves status. The performance analysis of such an asset should be enhanced with new diagnostic tools and modern methods of data integration. The current study has made a choice in favor of using a PRIME analysis which is multi-parametric analytical workflow based on a set of conventional and non-conventional diagnostic metrics. The most effective diagnostics in this study have happened to be those are based on 3D dynamic micro-models, which are auto-generated from the reservoir data logs. PRIME also provided useful insights on well performance, formation properties and the current conditions of drained reserves which helped to select the candidates for infill drilling, pressure maintenance, workovers, production target adjustments and additional surveillance. The paper illustrates the entire PRIME workflow, starting from the top-level field data analysis, all the way to generating a summary table containing well diagnostics, justifications and recommendations.

Field Optimization Via Data Approach: A Case Study of Data Mining for Tight Gas Flowback Evaluations

2021 ◽  
Author(s):  
Yuan Liu ◽  
Bin Li ◽  
Hongjie Zhang ◽  
Fan Yang ◽  
Guan Wang ◽  
...  
Keyword(s):  
Data Mining ◽  
Production Performance ◽  
Reservoir Quality ◽  
Tight Gas ◽  
Well Performance ◽  
Gas Field ◽  
Field Development ◽  
Field Level ◽  
Depth Analysis ◽  
The Impact

Abstract The economics of tight gas fields highly depend on the consistency between expected production and the actual well performance. A mismatch between the reservoir quality and the well production often leads to a review of the individual well. However, such mismatch may vary from case to case, and it is hard to perform a field-level analysis based on individual well reviews. We introduce a new method based on data mining to assist the field-level diagnosis. LX gas field is located the in eastern Ordos basin. Compared to the main gas field in the center of the basin, LX field is less predictable in well performance. This predictability issue hinders field development in LX field because the field economics are substantially jeopardized by the inconsistency between the reservoir quality and the production performance. The traditional workflow to understand this issue at the field level is to review the details of a large number of individual wells in the area. This is typically an intense task, and too much detail from multiple disciplines may hide the true pattern of the field behavior. To resolve this issue, we applied data mining in our field development diagnosis workflow. Our new workflow in LX area started with the existing field datasheet, including logging summaries, completion treatment reports, and flowback testing datasheets. With the data extracted from these different sources, we visualized the consolidated information in various plots and graphs based on regression analysis, which revealed the relation between flowback ratio and the production, the flowback rate consistency from the different service suppliers, and the impact of water productions. The data mining approach helped to generate new understandings in LX gas field. With the in-depth analysis of the flowback data together with reservoir properties and operation parameters, the key problems in the field were identified for further development optimization, and the field economics can be significantly improved. The diagnosis method can be easily adapted and applied to any field with similar problems, and data mining can be useful for almost all large-scale field development optimizations.

High-Resolution Numerical Modeling of Complex and Irregular Fracture Patterns in Shale-Gas Reservoirs and Tight Gas Reservoirs

2013 ◽  
Vol 16 (04) ◽  
pp. 443-455 ◽  
Author(s):  
O.M.. M. Olorode ◽  
C.M.. M. Freeman ◽  
G.J.. J. Moridis ◽  
T.A.. A. Blasingame
Keyword(s):  
Shale Gas ◽  
Flow Behavior ◽  
Production Performance ◽  
Tight Gas ◽  
Gas Reservoirs ◽  
Unconventional Gas ◽  
Fracture Patterns ◽  
Wide Range ◽  
Unconventional Gas Reservoirs ◽  
Secondary Fractures

Summary Various models featuring horizontal wells with multiple fractures have been proposed to characterize flow behavior over time in tight gas systems and shale-gas systems. Currently, little is known about the effects of nonideal fracture patterns and coupled primary-/secondary-fracture interactions on reservoir performance in unconventional gas reservoirs. We developed a 3D Voronoi mesh-generation application that provides the flexibility to accurately represent various complex and irregular fracture patterns. We also developed a numerical simulator of gas flow through tight porous media, and used several Voronoi grids to assess the potential performance of such irregular fractures on gas production from unconventional gas reservoirs. Our simulations involved up to a half-million cells, and we considered production periods that are orders of magnitude longer than the expected productive life of wells and reservoirs. Our aim was to describe a wide range of flow regimes that can be observed in irregular fracture patterns, and to fully assess even nuances in flow behavior. We investigated coupled primary/secondary fractures, with multiple/vertical hydraulic fractures intersecting horizontal secondary "stress-release" fractures. We studied irregular fracture patterns to show the effect of fracture angularity and nonplanar fracture configurations on production. The results indicate that the presence of high-conductivity secondary fractures results in the highest increase in production, whereas, contrary to expectations, strictly planar and orthogonal fractures yield better production performance than nonplanar and nonorthogonal fractures with equivalent propped-fracture lengths.

From Technical Evolution to Production Performance: A Technical Review of 700 Wells Over 8 Years in the South Sulige Tight Gas Field

2022 ◽  
Author(s):  
Dong Wang ◽  
Yifan Dong ◽  
Shengfang Yang ◽  
Joel Rignol ◽  
Qiang Wang ◽  
...  
Keyword(s):  
Joint Venture ◽  
Ordos Basin ◽  
Production Performance ◽  
Reservoir Quality ◽  
Tight Gas ◽  
Well Performance ◽  
Gas Field ◽  
Technical Review ◽  
The Ordos Basin ◽  
High Level

Abstract Unlike many unconventional resources that demonstrate a high level of heterogeneity, conventional tight gas formations often perform consistently according to reservoir quality and the applied completion technology. Technical review over a long period may reveal the proper correlation between reservoir quality, completion technology, and well performance. For many parts of the world where conventional tight gas resources still dominate, the learnings from a review can be adapted to improve the performance of reservoirs with similar features. South Sulige Operating Company (SSOC), a joint venture between PetroChina and Total, has been operating in the Ordos basin for tight gas since 2011. The reservoir is known to have low porosity, low permeability, and low reservoir pressure, and requires multistage completion and fracturing to achieve economic production. Over the last 8 years, there has been a clear technical evolution in South Sulige field, as a better understanding of the reservoir, improvement of the completion deployment, optimized fracturing design, and upgraded flowback strategy have led to the continuous improvement of results in this field. Pad drilling of deviated boreholes, multistage completions with sliding sleeve systems, hybrid gel-fracturing, and immediate flowback practices, gradually proved to be the most effective way to deliver the reservoir's potential. Using the absolute open-flow (AOF) during testing phase for comparative assessment from South Sulige field, we can see that in 2012 this number was 126 thousand std m3/d in 2012, and by 2018 this number had increased to 304 thousand std m3/d, representing a 143% incremental increase. Thus, technical evolution has been proved to bring production improvement over time. Currently, South Sulige field not only outperforms offset blocks but also remains the top performer among the fields in the Ordos basin. The drilling and completion practices from SSOC may be well suited to similar reservoirs and fields in the future.

scholarly journals Unconventional Gas Production from Hydraulically Fractured Well-An Application of Direct Search Based Optimization Algorithm

2019 ◽  
Vol 8 (2S11) ◽  
pp. 2726-2737
Keyword(s):  
Objective Function ◽  
Fracture Propagation ◽  
Gas Production ◽  
Production Model ◽  
Tight Gas ◽  
Gas Reservoirs ◽  
Unconventional Gas ◽  
Fracture Geometry ◽  
Propagation Behavior ◽  
Fractured Well

Unconventional gas reservoirs are now the targets for meeting the demand for gas. These reservoirs are at the depth of more than 10,000 ft (even over 15000 depth as well) and are difficult to be exploited by conventional methods. For the last decades hydraulic fracturing has become the tool to develop these resources. Mathematical models (2D and pseudo-3D) have been developed for fracture geometry, which should be realistically created at the depth by surface controllable treatment parameters. If the reservoir rock is sandstone, then proppant fracturing is suitable and if the rock is carbonates, then acid fracturing is applicable. In both cases, proper design of controllable treatment parameters within constraints is essential. This needs proper optimization model which gives real controllable parametric vales. The model needs the most important analyses from geomechanical study and linear elastic fracture mechanics of rock containing unconventional gas so that fracture geometry makes maximum contact with the reservoirs for maximum recovery. Currently available software may lack proper optimization scheme containing geomechanical stress model, fracture geometry, natural fracture interactions, real field constraints and proper reservoir engineering model of unconventional gas resources, that is, production model from hydraulically fractured well (vertical and horizontal). An optimization algorithm has been developed to integrate all the modules, as mentioned above, controllable parameters, field constraints and production model with an objective function of maximum production (with or without minimization of treatment cost). Optimization is basically developed based on Direct Search Genetic and Polytope algorithm, which can handle dual objective function, non-differentiable equations, discontinuity and non-linearity. A dual objective function will meet operator’s economic requirements and investigate conflict between two objectives. The integrated model can be applied to a vertical or horizontal well in tight gas or ultra-tight shale gas deeper than over 10,000 ft. A simulation (with industrial simulators) was conducted to investigate and analyse fracture propagation behavior, under varying parameters with respect to the fracture design process, for tight gas reservoirs. Results indicate that hydraulic fracture propagation behavior is not uninhibited in deep reservoirs as some may believe that minor variations of variables such as in-situ stress, fluid properties etc. are often detrimental to fracture propagation in some conditions. Application of this model to a hypothetical tight and ultra-tight unconventional gas formations indicates a significant gas production at lower treatment cost; whereas the resources do not flow without any stimulation (hydraulic fracturing).

Beyond Volumetrics: Unconventional Petrophysics for Efficient Resource Appraisal (Example from the Khazzan Field, Sultanate of Oman)

2015 ◽  
Author(s):  
David R. Spain ◽  
German D. Merletti ◽  
William Dawson
Keyword(s):  
Gas Permeability ◽  
Stress Profile ◽  
Tight Gas ◽  
Well Performance ◽  
Flow Properties ◽  
Dynamic Flow ◽  
Stress Regime ◽  
Flow Units ◽  
Fluid Saturation ◽  
Rock Typing

Abstract The Middle East region holds substantial resources of unconventional tight gas and shale gas. The efficient extraction of these resources requires significant technology and expertise across numerous disciplines, including reservoir description and geomechanical characterization, hydraulic fracture modelling and design, advanced numerical simulation capabilities, sensor and surveillance technologies, and tightly integrated workflows. The effective application of these integrated subsurface and completion workflows leads to improved capital efficiency and well performance through increased well potential, increased ultimate recovery, and reduced costs. Key elements include dynamic rock typing to highlight potential flow units that will maximize gas deliverability, geomechanical modelling to provide a calibrated stress profile, and an integrated model that demonstrates the importance of understanding both dynamic flow properties and geomechanical response in complex tectonic environments. Dynamic rock typing focuses on using both depositional and petrophysical properties including rock type, porosity, and effective gas permeability at reservoir conditions to divide the reservoir into flow units in the context of their saturation history. The geomechanical profiling generates a tectonics-corrected minimum horizontal stress (SHmin) and the net confining stress (NCS). The rock-log-test calibration requires the evaluation and integration of subsurface fracture tests, including After-Closure Analysis (ACA), Data Fracs and Micro Fracs. All three involve different injection volumes and sampled reservoir volumes. Tight gas petrophysical studies must go “beyond volumetrics”, and should consider not only the static (storage) and dynamic (flow) properties within the context of the petroleum system and evolution of the current day pore geometry and fluid saturation distribution, but also the geomechanical stress regime and its implications for efficient completion optimization. Alternative interpretations test the range of uncertainty and are useful in designing field trials and surveillance strategies to reduce the subsurface uncertainty and to mitigate development risks.

Field-Proven Well Surveillance Techniques Designed for an Early Well Scaling Diagnosis and Timely Well Performance Reinstatement: Case Study from the Kashagan Field

2021 ◽  
Author(s):  
Aktoty Kauzhanova ◽  
Lyudmila Te ◽  
John Reedy ◽  
Thaddeus Ivbade Ehighebolo ◽  
Mirko Bastiaan Heinerth ◽  
...  
Keyword(s):  
Surveillance Program ◽  
Successful Implementation ◽  
Well Testing ◽  
Well Performance ◽  
Root Cause ◽  
Operating Environments ◽  
Initial Stage ◽  
Calcite Deposition ◽  
Time Required

Abstract Some wells in the Kashagan field did not perform as well as expected. Despite producing virtually no water, calcite deposition was found to be the root cause of the problem. A comprehensive well surveillance program, which was proven to be very efficient for an early scaling diagnosis, was developed by the operator, North Caspian Operating Company (hereafter NCOC). As a result, well scaling is currently well managed and prevented from reoccurring. The objective of this paper is to share an early experience with well scaling in the Kashagan field, as well as to describe the developed set of well surveillance techniques. The aim of the various well surveillance techniques discussed in this paper is to improve an Operator's ability to identify the very first signs of scale accumulation. This, in its turn, enables to introduce timely adjustments to the well operating envelope and to schedule a scale remediation / inhibition treatment with the intention to prevent any potential scaling initiation from further development. The approach is quite extensive and incorporates continuous BHP/BHT monitoring, routine well testing, PTA analysis, and fluid/water sampling. Developed approach experienced multiple revisions and modifications. Further optimization continues, however, the described well surveillance techniques represent the latest Operator's vision on the most efficient way for well scaling monitoring and identification. In the Kashagan field, BHP/BHT readings have proved to be the most direct and instantaneous indication of any early signs of potential deterioration in well performance (qualitative analysis) while well testing and PTAs are considered as the most essential techniques in confirming and quantifying scaling severity (quantitative analysis). It is important to mention that BHT increase is explained by Joule-Thomson heating effect being specific for the Kashagan fluid (happening during increased pressure drawdown). This, in turns, enables to predict future well performance, design well operating envelop accordingly and, most importantly, develop a yearly schedule for proactive well treatments with SI. In conclusion, it shall be highlighted that discussed complex of well surveillance techniques has been concluded to be very efficient and reliable tool in identifying any scaling tendencies at its initial stage. Due to successful implementation of this approach in the Kashagan field, scale development is now well-managed and kept under control. To mention, that utilization of well surveillance techniques and methods outlined in this paper may reduce the time required to identify and ultimately mitigate well scale accumulation in any active assets with similar operating environments.

Application Investigation of Light Proppant in Hydraulic Fracturing of Marcellus Shale

2021 ◽  
Author(s):  
Aymen Alhemdi ◽  
Ming Gu
Keyword(s):  
History Matching ◽  
Marcellus Shale ◽  
In Situ Stress ◽  
Production Performance ◽  
Well Performance ◽  
Fracture Permeability ◽  
Fracture Conductivity ◽  
Stimulated Reservoir Volume ◽  
Conductivity Distribution ◽  
Cumulative Production

Abstract Slickwater-sand fracturing design is widely employed in Marcellus shale. The slickwater- sand creates long skinny fractures and maximizes the stimulated reservoir volume (SRV). However, due to the fast settling of sand in the water, lots of upper and deeper areas are not sufficiently propped. Reducing sand size can lead to insufficient fracture conductivity. This study proposes to use three candidate ultra-lightweight proppants ULWPs to enhance the fractured well performance in unconventional reservoirs. In step 1, the current sand pumping design is input into an in-house P3D fracture propagation simulator to estimate the fracture geometry and proppant concentrations. Next, the distribution of proppant concentration converts to conductivity and then to fracture permeability. In the third step, the fracture permeability from the second step is input into a reservoir simulator to predict the cumulative production for history matching and calibration. In step 4, the three ULWPs are used to replace the sand in the frac simulator to get new frac geometry and conductivity distribution and then import them in reservoir model for production evaluation. Before this study, the three ULWPs have already been tested in the lab to obtain their long-term conductivities under in-situ stress conditions. The conductivity distribution and production performance are analyzed and investigated. The induced fracture size and location of the produced layer for the current target well play a fundamental effect on ultra-light proppant productivity. The average conductivity of ULWPs with mesh 40/70 is larger and symmetric along the fracture except for a few places. However, ULWPs with mesh 100 generates low average conductivity and create a peak conductivity in limited areas. The ULW-3 tends to have less cumulative production compared with the other ULWPs. For this Marcellus Shale study, the advantages of ultra-lightweight proppant are restricted and reduced because the upward fracture height growth is enormous. And with the presence of the hydrocarbon layer is at the bottom of the fracture, making a large proportion of ULWPs occupies areas that are not productive places. The current study provides a guidance for operators in Marcellus Shale to determine (1) If the ULWP can benefit the current shale well treated by sand, (2) what type of ULWP should be used, and (3) given a certain type of ULWP, what is the optimum pumping schedule and staging/perforating design to maximize the well productivity. The similar workflow can be expanded to evaluate the economic potential of different ULWPs in any other unconventional field.

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