Fracturing fluid may jeopardize the production of hydraulically fractured tight gas formations. As capillary forces are acting stronger in low permeable formation, the invaded fracturing fluid is harder to be removed. The increase of water saturation around the fractured well affects the mobility of the gas phase, particularly in tight formations where the gas relative permeability declines strongly when water saturation increases. This damage might greatly reduce the gas production in a
very long cleanup period. This paper presents numerical simulation techniques to account for formation damage with both a near-well model and a full-field model for fractured wells in tight formations and to integrate damage effects in a full-field reservoir model through an efficient coupled modelling.
This paper discusses issues encountered by an operating company in West Bengal, India and how technological, operational, and engineering solutions were applied to resolve them. The goal was to complete a well with only one coiled tubing (CT) trip while placing several pinpoint hydraulic fractures, thus increasing efficiency. The solution entailed using hydrajet perforating combined with annular pumping and proppant plugs for diversion.
Combining production from multiple intervals within a well during completion has been used for many years. Many of these reservoirs required hydraulic-fracture stimulation, and a number of promising fracturing methods have been developed where several stages can be performed sequentially, provided there is some method used to isolate previously stimulated intervals.
One method claims high efficiency by using high-rate treatments and limited-entry perforating concepts. However, the promises proved to be elusive. Contingencies for early screenout, perforating gun missfires, and other equipment failures have often dramatically impacted completion efficiency. To guard against these failures, the proppant schedules were underdesigned or purposely overflushed, thus reducing the resulting fracture conductivity.
To achieve limited-entry diversion, high-treatment rates were used, which required a large amount of hydraulic horsepower onsite. Yet, even when efficiencies were achievable, production logging often showed that, at best, only 50% of the intended fracturing targets would actually produce at fracture-stimulated rates. Discovery of an important phenomenon was recently explained using computational fluid dynamics (CFD) simulation. It was found that the difference in the physical qualities of proppant and the carrying fluid cause the upper intervals to receive mostly proppant-free fluid.
Pinpoint-stimulation fracturing methods can allow all of the multiple intervals completed to be stimulated efficiently, such that all intervals received the designed proppant volumes one interval at a time. For the most effective of these methods, coiled tubing (CT) is used to hydrajet perforate intervals for individual fracturing treatments, and proppant plugs are used to isolate stimulated intervals while maximizing near-wellbore (NWB) conductivity. These methods do not require removing the CT from the well between treatments, so early screenouts can be remediated immediately with minimal impact.
A new entry in this class of fracturing that allows real-time, on-demand downhole proppant-schedule control can be combined with real-time fracture-mapping diagnostics to optimize stimulated reservoir volume (SRV) on-the-fly, when needed. A 15-stage completion in the Marcellus is used to demonstrate the process.
In 2009, a service company performed its first hydraulic fracturing treatment using a conventional hydraulic-fracturing technique in coalbed methane (CBM) wells in India. As progress was made, the potential for performing an extensive number of hydraulic-fracturing treatments in CBM wells was observed. From an operational standpoint, the advantages of recovering CBM wells are that they have more target coal seams at shallower depths that are candidates for stimulation, and the size of the treatments makes them ideal for multiple applications in a shorter period of time, reducing nonproductive time (NPT) for the operating company (Seldle and Arri 1990).
The service company introduced a unique fracturing service that integrated two components—coiled-tubing (CT) deployed hydrajet perforating and then immediately performing hydraulic fracturing. By combining these two processes into one continuous service operation it eliminates the use of wireline for perforating and plug setting, making the new multistage technology economical for CBM wells. For the first time in India, this CT perforating/fracturing service was introduced to a CBM well operator. The observations and knowledge gained from the fracturing-service operations in India are discussed in this paper.
This process employed hydrajetting technology through CT using a hydrajetting tool in the bottomhole assembly (BHA). Based on the casing specifications, cementing conditions, rock properties, and experience gained with each perforating experience, the jetting flow rates, differential pressures, and casing annulus backpressure requirements were optimized. This increased the life of the tool and improved the overall operations. The hydrajetting tool life was increased from 6 to 8 perforation sets to about 19 to 21 per tool, improving the operational efficiency. The advantages of jetting acid into the created perforations, pressure squeezing with acid, and using the many services of CT are examined. In addition, the BHA is also discussed.
In some of the frac stages, the treatment screened out and experienced high concentrations of sand in the wellbore; therefore, the steps taken to help prevent sanding off the tool or getting the CT stuck are reviewed. Sand concentrations of 12 lbm/gal. were achieved for extended periods of time to pack the formations off. The need for using wellbore sand plugs was eliminated for many frac stages in these wells as a result of successfully packing the proppant into the fractures with higher sand concentrations. This helped eliminate concerns of losing fluid and sand into previous fractures when performing new frac stages uphole.
As more treatments were executed and experience was gained, fluid usage was optimized and the fluid consumption was reduced by approximately 30 to 40%, providing further value to the operator. Finally, the lessons learned from a project-management viewpoint are also examined, discussing streamlining operations based on the various field and reservoir conditions experienced in India.
The knowledge gained from this project could be directly applicable to the fracturing-service operations in other regions with CBM wells. The operational learnings during the course of this project could also serve as a guide to operations in this region where similar challenges are encountered.
Tight gas reservoirs show challenges to geologists to characterize because of their tendency to be generally heterogeneous due to depositional and diagenetic processes. The value petrophysical properties are very valuable in static and dynamic reservoir modeling. This paper presents a prediction of Klinkenberg permeability by using artificial neural network, composite logs and core data in basin in western USA. The klinkenberg model approximates a linear relation between the measured gas permeability and the reciprocal absolute mean core pressure. This model has been a consistent basis for the development of methods computing the absolute liquid permeability of a core sample based on a single data point.
In tight gas reservoir with increasing in gas slippag ( klinkenberg effect) cause to decrease in pore-throat size and permeability parameters. In advanced there were some method to determine Klinkenberg permeability in situ which can be obtained by measuring just routine air permeability and Klinkenberg parameter such as byrnes in 1997 & 2003 but these ways intensively depend on core permeability, so it needs some core plugs and inevitably we have to spend much time and money.
The goal in this study was to research about relationship between core Klinkenberg permeability and composite logs (gamma ray, density, neutron and formation resistivity and so on) by using MLP & Back Propagation methods (Artificial neural network) to characterize the Klinkenberg permeability in situ in 3 different wells in 3 stages (training, validation and application) with suitable core calibration. For two wells there is very good core calibration and the R2 is more than 0.7 in training and application processes.
The importance of evaluation of tight gas reservoir with high heterogeneity by using artificial neural network and conventional logs is spending less capital or time and finally obtaining reliable Klinkenberg permeability in situ.
Al Gazal, Mohammed (Saudi Aramco) | Abel, Justin Tate (New Tech Global) | Wilson, Stuart (Schlumberger Well Services) | Wortmann, Henry (Schlumberger Well Services) | Johnston, Bryan Bruce (Packers Plus)
Open hole multistage fracturing (MSF) completions are becoming standard practice in the south gas fields development in Saudi Arabia with more than 25 wells completed to date using open hole packers and selective port technology.
Overall, the production results from the use of MSF completions have been very positive and the forecast is that MSF technology usage will grow considerably over the next several years. In general, MSF completions provide an excellent advantage in that they are intervention-less in their standard mode of operation. An aspect that is evolving is the secondary use of coiled tubing (CT) to handle the planned and unplanned (contingency) operations occasionally required to reach well production objectives. Without optimum operational planning and the selection of correct CT downhole tools, completion problems can be encountered and this ultimately can result in the job objective not being reached at all or only at increased costs. In addition, the use of CT to function ball-activated ports to shut off zones or to re-stimulate is starting to be appreciated.
This paper presents MSF case studies where CT has been deployed and investigates the operational impact and productivity enhancement. Correlations taken from the key hardware variables, such as fracturing port size and type, motor type, mill bit type, and CT size, are also considered and analyzed.
Following the lessons learned and best practices from these experiences, with correct implementation, the findings from this paper should increase the potential for successful multistage completion operations and ultimate improvements in productivity. These guidelines can thus be transferable to other operators using similar
MSF completion technologies.
Shrivastva, Chandramani (Schlumberger) | Al-Mahruqy, Sultan Hamed (Petroleum Development Oman) | Mjeni, Rifaat (Petroleum Development Oman) | Al Kindy, Sueliman (Schlumberger) | Hosein, Feraz (Schlumberger Oman) | Al-Busaidi, Hafidh (Schlumberger Oman) | Al-Busaidi, Jokha (Schlumberger) | Laronga, Robert J.
Borehole images play a crucial role in tight gas exploration. Recognition of sedimentary features helps in understanding the depositional architecture and allows refinement of the facies model for flow unit identification and stimulation treatment. The structural analysis of faults and fractures provides clues not only about the tectonic history, but also about the possible conduits for fluid migration that lead to diagenesis. The diagenetic imprints and their impact in a sequence stratigraphic
framework can be understood through textural analysis performed on the borehole images across the field. And, hydrofracturing of tight gas reservoirs require important input from the borehole images in understanding the variability of stress regimes.
Established micro-resistivity imagers for the water-base mud (WBM) environment provide robust results, except when there is a large contrast between the formation resistivity (Rt) and the mud resistivity (Rm). With more frequent use of hyper-saline mud, a new and improved definition imager is deployed to obtain high quality images. Novel hardware and improved signal processing algorithms are employed to acquire the images despite the hostile conditions provided by the combination of lowresistivity salt-saturated (WBM) and high formation resistivity that would otherwise impede the data quality. Early field testing of this enhanced capability took place in the Sultanate of Oman and the examples of its improved performance are presented.
Getting the most detailed image data in oil-base mud (OBM) is challenging compared to the WBM systems. As an alternative to the options commercially available in the industry today, the new high-definition imager developed for the WBM system can also be used under favorable conditions to acquire valid images in the OBM. The high-definition imager works best in OBM when both formation resistivity and mud permittivity are high.
A workflow is developed for the Go - No Go decisions for borehole imaging tools in different mud systems for tight gas reservoirs. It is important at the planning phase of the logging programs to anticipate the imaging tool behavior in the proposed mud system and conditions. The results from trials made in the tight gas reservoirs of North Oman provided the basis for a decision tree for imaging, since the logging environment exerts a strong control on data quality. The decision-tree presented here aims to ensure that images acquired are the most suitable for detailed geologic interpretation and subsequent integration in development plans for optimal exploitation of tight gas sands in Oman.
Technological advances and improved operational efficiency have made unconventional resources around the globe far more lucrative for producers. The challenge in recovering hydrocarbons from unconventional resources is low permeability, making it essential that a cost-efficient fracture-stimulation treatment program be performed. However, while the wells being completed are economical, are operators truly capitalizing on their full potential?
The process of fracturing unconventional reservoirs has remained virtually unchanged in recent years. Stimulation treatments are pumped at high rates through multiple perforation clusters over a large interval and isolated using mechanical plugs. This poses several problems:
- Uncertainty of the number of fractures created.
- Uncertainty of proppant placement into fractures.
- Costly and time-consuming recovery from screenouts.
- Pumping plugs results in overflushing the near-wellbore.
- Treatment changes cannot be seen at the perforations until a casing volume is pumped.
- Increased cost, footprint, personnel, and hydraulic-horsepower (HHP) requirements.
This paper presents a high-rate coiled tubing (CT) fracturing technique that enables customized fracture treatments to help maximize stimulated reservoir volume (SRV) by manipulating flow rate and proppant concentration at the perforations in response to reservoir pressure. Therefore, every gallon of fluid and every pound of proppant can be used to effectively stimulate the formation. Recovery from screenouts is fast because of having coil in-hole, but the functionality of the process enables screenouts to be avoided all together. At the end of the treatment, the well is simply cleaned out, and the entire operation is completed with only one trip in hole and with no plugs to be drilled out. These benefits combined can maximize return on investment for the operator. This paper includes a side-by-side comparison of this technique with a conventional fracturing treatment, weighing risk, stimulation effectiveness, operational efficiencies, and cost savings.
Rahim, Zillur (Saudi Aramco) | Al-anazi, Hamoud Ali (Saudi Aramco) | Kanaan, Adnan (Saudi Aramco) | Habbtar, Ali Hussain (Saudi Aramco) | Omair, Ahmed M. (Saudi Aramco) | Senturk, Nejla Halime (Saudi Aramco) | Kalinin, Daniel Anatolievitch (Schlumberger Middle East)
Hydraulic fracturing technology is widely used to facilitate and enhance the gas recovery process from conventional and tight gas resources. Tight gas or unconventional reservoirs, that include very low permeability sandstones, carbonates, or shales, cannot be economically produced without hydraulic fracturing. Recently, much progress has taken place in the overall hydraulic fracturing procedures and the field implementations of advanced stimulation technology have produced good results. The proper selection of well trajectory, gel concentration, polymer loading, proppant type/size and concentration, perforation methods, locations for packer and frac port placement in a multistage fracturing assembly, number of fracture stages to cover the net pay, etc., have all contributed to
successful stimulation and improved gas recovery. Even though stimulating gas reservoirs has become a routine application and much experience has been gained in this area, not all treatments are straightforward without problems and challenges. Unless a stimulation treatment is carefully designed and implemented, the post-stimulation results in moderate to tight reservoirs may not be encouraging, and can easily fall below expectation.
The most essential step to close the gap between expected results and actual well performance is to understand reservoir characteristics and its potential to produce at a sustained rate after a successful fracturing treatment. Overestimation of reservoir flow capacity and achieved fracture geometry will also over-predict well performance.
This paper addresses the importance and impact of detailed reservoir characterization and superior stimulation processes on final well performance. Several field examples from Saudi Arabia's gas reservoirs are presented in the paper showing the value of effective well planning, reservoir characterization, application of hydraulic fracturing, and proper cleanup.
The paper also illustrates the impact of drilling trajectory and wellbore reservoir connectivity on the proper placement of desired hydraulic fracture treatments and sustained gas production.
Low permeability and complexities of rock formation in tight gas resources make it more complicated to predict well production performance and estimate gas recovery. To produce from the unconventional resources in the case that formation rock is not sensitive to damage caused by liquid invasion, hydraulic fracturing is the most common stimulation treatment to improve the production to the excepted economically rate.
In term of reservoir geometry, tight sand formations are normally stacks of isolated lenses of sand bodies that are separated by shale layers. Each sand lens varies in shape and size and acts as a trap for original hydrocarbon accumulations. The sand lenses parameters such as length and width can play important role in controlling gas recovery from hydraulically fractured tight gas reservoirs.
This study shows the effect of drainage pattern of the lenticular sand bodies on production performance and ultimate gas recovery in tight gas formations. Analytical and numerical simulation approaches are used in order to understand the effect of hydraulic fracture parameters and also attribution of sand lens size and shape to the drainage pattern and gas recovery in hydraulically fractured tight sand gas reservoirs.
The results highlighted that in tight gas with massive hydraulic fractures, sand lens size in the direction perpendicular to hydraulic fracture wings has the major impact on gas recovery. Sand lens size in the direction parallel to hydraulic fracture wings does not have significant effect on gas recovery. When the sand lenses are isolated and small in size, from a single well-enhancement perspective, the gas recovery will increase significantly by performing massive hydraulic fracturing
through isolated lenses.