Al-Nakhli, Ayman (Saudi Aramco) | Tariq, Zeeshan (King Fahd University of Petroleum and Minerals) | Mahmoud, Mohamed (King Fahd University of Petroleum and Minerals) | Abdulraheem, Abdulazeez (King Fahd University of Petroleum and Minerals) | Al-Shehri, Dhafer (King Fahd University of Petroleum and Minerals) | Murtaza, Mobeen (King Fahd University of Petroleum and Minerals)
Recent rise in global warming and fluctuations in world economy needs the best engineering designs to extract hydrocarbons from unconventional resources. Unconventional resources mostly found in over-pressured and deep formations, where the host rock has very high strength and integrity. Fracturing techniques becomes very challenging when implemented in these types of rocks, and in many cases approached to the maximum operational limits without generating any fracture. This leaves a small operational window to initiate and place the hydraulic fractures. Current stimulation methods to fracture these formations involve with adverse environmental effects and high costs due to the entailment of water mixed with huge volumes of chemicals such as biocides, scale inhibitors, polymers, friction reducers, rheology modifiers, corrosion inhibitors, and many more.
In this study, a novel environmentally friendly approach to reduce the breakdown pressure of the unconventional rock is presented. The new approach makes it possible to fracture the high strength rocks more economically and in more environmentally friendly way. The new method incorporates the injection of chemical free fracturing fluid in a series of cycles with a progressive increase of pressure in every cycle. This will allow stress relaxation at the fracture tip and correspondingly enough time for fracturing fluid to infiltrate deep inside the rock sample and weaken the rock matrix. As a result of which the tensile strength-ultimately the breakdown pressure of the rock gets reduced. The present study is carried out on different cement blocks.
The post treatment experimental analysis confirmed the success of cyclic fracturing treatment. The results of this study showed that the newly formulated method of cyclic injection can reduce the breakdown pressure by up to 24% of the original value. This reduction in breakdown pressure helped to overcome the operational limits in the field and makes the fracturing operation greener.
Al-Nakhli, Ayman (Saudi Aramco) | Tariq, Zeeshan (King Fahd University of Petroleum and Minerals) | Mahmoud, Mohamed (King Fahd University of Petroleum and Minerals) | Abdulraheem, Abdulazeez (King Fahd University of Petroleum and Minerals) | Al-Shehri, Dhafer (King Fahd University of Petroleum and Minerals)
Current global energy needs require best engineering methods to extract hydrocarbon from unconventional resources. Unconventional resources mostly found in highly stressed and deep formations, where the rock strength and integrity both are very high. The pressure at which rock fractures or simply breakdown pressure is directly correlated with the rock tensile strength and the stresses acting on them from surrounding formation. When fracturing these rocks, the hydraulic fracturing operation becomes much challenging and difficult, and in some scenarios reached to the maximum pumping capacity limits. This reduces the operational gap to create hydraulic fractures.
In the present research, a novel thermochemical fracturing approach is proposed to reduce the breakdown pressure of the high-strength rocks. The new approach not only reduces the breakdown pressure but also reduces the breakdown time and makes it possible to fracture the high strength rocks with more conductive fractures. Thermochemical fluids used can create microfractures, improves permeability, porosity, and reduces the elastic strength of the tight rocks. By creating microfractures and improving the injectivity, the required breakdown pressure can be reduced, and fractures width can be enhanced. The fracturing experiments presented in this study were conducted on different cement specimen with different cement and sand ratio mixes, corresponds to the different minerology of the rock. Similar experiments were also conducted on different rocks such as Scioto sandstone, Eagle Ford shale, and calcareous shale. Moreover, the sensitivity of the bore hole diameter in cement block samples is also presented to see the effect of thermochemical on breakdown pressure reduction.
The experiments showed the presence of micro-fractures originated from the pressure pulses raised in the thermochemical fracturing. The proposed thermochemical fracturing method resulted in the reduction of breakdown pressure to 38.5 % in small hole diameter blocks and 60.5 % in large hole diameter blocks. Other minerology rocks also shown the significant reduction in breakdown pressure due to thermochemical treatments.
Improved completion design and field development strategies have provided commodity price resilience by sustained efficiency gains across most major US Shale plays. This rapid evolution in completion practices, however, has created behind pipe opportunities. Refracturing offers a viable solution to maximize on these opportunities, however, its effectiveness is dependent on a variety of factors. The present paper explores the implementation of refracturing as a re-development strategy in legacy shale plays and evaluates it as a truly multivariable problem.
The paper takes into consideration petrophysical parameters, initial completion design, chemical composition, formation quality, time from original completion, refrac completion design and production performance to quantify impact on refrac KPIs such as IP ratio, EUR ratio, decline trend impact, amongst others. The paper does this by using an ACE (alternating conditional expectation) non-linear regression model that incorporates the KPI’s as response variables and utilizes the transforms of a wide range of input variables to identify cause and effect relationships. By running this analysis across multiple legacy shale plays, including the Haynesville, and Barnett, the paper provides best-practices to maximize refracturing success.
While refrac can offer a viable solution in obtaining incremental production, depending on the basin, a refrac can be a tenth of the expense of a new well and can beneficially impact the production from the existing well. In most cases, the analysis found EUR predictions improved by 30% - 200%. While correlations varied across basins and completion design, an inverse correlation was found between refrac KPIs and initial frac intensity.
Although, refracturing in horizontal shale wells is a well-established practice, a significant amount of analysis on their performance is focused on one or two key variables. The present paper adds to the existing body of literature by using data analytics and machine learning to evaluate this strategy from a truly multivariable standpoint. The paper also provides best practices to evaluate and predict refrac performance to de-risk refrac as a field re-development strategy.
This course discusses the fundamental sand control considerations involved in completing a well and introduces the various sand control techniques commonly used across the industry, including standalone screens, gravel packs, high rate water packs and frac-packs. It requires only a basic understanding of oilfield operations and is intended for drilling, completion and production personnel with some sand control experience who are looking to gain a better understanding of each technique’s advantages, limitations and application window for use in their upcoming completions.
Tight gas reservoirs generate many difficult problems for geologists, engineers, and managers. Cumulative gas recovery (thus income) per well is limited because of low gas flow rates and low recovery efficiencies when compared to most high permeability wells. To make a marginal well into a commercial well, the engineer must increase the recovery efficiency by using optimal completion techniques and decrease the costs required to drill, complete, stimulate, and operate a tight gas well. To minimize the costs of drilling and completion, many managers want to reduce the amount of money spent to log wells and totally eliminate money spent on extras such as well testing. However, in these low-permeability layered systems, the engineers and geologists often need more data than is required to analyze high permeability reservoirs.
The definition of unconventional reservoirs continues to evolve over time as advances in technology make it more viable to extract hydrocarbons. The need for reservoir characterization in such reservoirs, however, will continue to increase to optimize wellbore placement and enhance production. For high-angle or horizontal wellbores common in unconventional drilling, obtaining information from wireline technologies may be either too expensive or risky, although obtaining a wellbore stability assessment while drilling provides a key input into the real-time geomechanical model. This paper presents field test results of a new 4¾-in. ultrasonic imaging logging-while-drilling (LWD) tool that provides a real-time assessment of borehole shape and high-resolution caliper and acoustic impedance images in both water-based mud (WBM) and oil-based mud (OBM) applications.
Images from measurements, such as gamma ray, resistivity, or density, are common in LWD applications. However, high-resolution images have historically been limited to WBM applications. This paper describes the sensor physics and tool configuration that enable the acquisition of borehole caliper and acoustic impedance images in all mud types, with examples of logs obtained while drilling in boreholes using OBM. Details of the comparison with wireline data sets are also given.
Vertical and horizontal wellbores covering different lithologies are described, showing that high-resolution images are now available in slimhole OBM applications. Caliper images illustrate small changes in borehole shape, and impedance images can be used to evaluate geological features and determine stratigraphic dip. The evaluation of caliper data with a wireline multifinger caliper illustrates the potential to eliminate a separate wireline run before completing the well. Comparison of while-drilling data with tripping out of hole data provides crucial insight into wellbore deterioration with time.
The technology described addresses key challenges encountered while drilling and evaluating unconventional reservoirs. Real-time wellbore stability assessment enables optimization of drilling parameters and mud weight in all unconventional reservoirs. Identification of faults and fractures provides valuable information to optimize the hydraulic fracturing program in shale gas applications. Inputs into the geomechanical model are valuable in the assessment of tight sand reservoirs with extremely low porosity and permeability. Limestone reservoirs with minor shale content may require OBM to minimize wellbore deterioration with time. Monitoring such deterioration is critical in optimizing the placement of packers and the hydraulic fracturing program design.
Providing the industry's highest-resolution images in all mud types, even under high logging speeds represents a unique method of assessing real-time wellbore stability and enhancing formation evaluation in slim wellbores in unconventional reservoirs.
Surfactants are used in gas well deliquification to generate foam to lift liquid condensates and brine from a well during gas production. In this paper, the effect of various hydrocarbon components typically found in natural condensates on selected foaming surfactants was studied. The screening methodology used a modified blender test to evaluate foam height and its half-life. The foaming results from the blender tests are reported for a number of alpha olefin sulfonates (AOS), alkyl ether sulfates (AES), and betaines at 25 C and ambient pressure. The surfactants were also evaluated using dynamic foam carry-over apparatus at ambient conditions for further validation. This work helps to elucidate problems associated with choosing the proper gas well deliquification surfactant suitable for a condensate of a specific composition.
The main objective is to extend the Moving Reference Point (MRP) application to hydraulic fracturing treatments in the Cotton Valley and Travis Peak formations at east Texas. The ability to make corrective decisions to the pumping schedule, as the treatment is ongoing, is one of the advantages of this kind of analysis. An understanding of the treatment pressure-time trend as a diagnostic tool can significantly improve the efficiency of future hydraulic fracturing treatments and enhance field development optimization.
The MRP technique was developed by
The results show the viability of the MRP technique in five wells completed across the Cotton Valley and Travis Peak formations. The disadvantages in the Nolte-Smith method, in terms of closure pressure (Pc) requirement and log-log scale, are compensated for by the MRP method through using the treating pressure and a Cartesian-type plot. Unlike the net pressure (Pnet)-time log-log plot, the fracture behavior/mode can be easily visualized by the
This paper is focused on the future fracture design improvement and what if the MRP was used while pumping. It shows the advantages of using such a technique as a reliable pressure-time diagnostic tool. The previous publications about the MRP discussed mainly the methodology and the fracture mode physical description. This paper offers suggestions to ultimately enhance the Cotton Valley and Travis Peak formations development and helps operators to make proper decisions on the fly during fracture treatments.
In this study, various upscaling techniques and their effects on Barik tight gas Formation simulation modelling results were investigated. The intent of this upscaling study is to recommend coarse models that provide approximately the same flow behavior or well performance as the fine grid model. The study will help to develop an awareness of the range of applicability for the upscaled coarse models. It will also allow coarse grid models to be used appropriately and with greater confidence in production optimization.
These techniques comprised several alternative ways of grouping reservoir data, with respect to petrophysical rock types (herein referred to as RT). This scheme defines 5 individual rock types, with RTs 1 to 4 broadly defining pay and RT 5 defining non-pay.
The layers in the simulation models are made up of single or multiple grouped RTs from the same zone. Keeping each layer in the model, ordered as it was in the well log, resulted in 85 simulation layers for the fine grid model. The upscaled or coarse models have 16 to 35 simulation layers, with the smallest being the model where RTs 1 to 4 are grouped together. Different RTs sorting were tested in each of the upscaled models.
The results of this study suggest that re-ordering the log information so that all of the rock for each rock type was grouped together inside each stratigraphic unit appears to be an acceptable upscaling technique that gives reasonable efficiency and accuracy. This type of upscaling was required since the study showed that any upscaling method that averaged the properties of RT 1 with the properties of other rock types within the same simulation layer could result in optimistic EUR estimates of up to 30% relative absolute error when compared to a fine grid model. The choice of upscaling method is particularly significant in a low Kv/Kh ratio environment, but less so within environments with a high Kv/Kh ratio.
The upscaling technique has only been tested for the Barik formation and should not be used elsewhere without proper testing. The upscaling technique works for the Barik formation because of several distinctive features of the reservoir and the wells. In applying this upscaling technique we assume that: The wells are all hydraulically fractured and thus the flow is generally horizontal into the fractures and from the fractures into the well. The fracture extends from the top to the bottom of each stratigraphic unit that the fracture encounters. If a fracture only partially penetrates a stratigraphic unit, this method may not work. The gas is relatively dry and thus the flow is less affected by gravity than for reservoirs containg flowing liquids. The reservoir is made up of rock with a wide range of permeability, but the flow is dominated by the well connected, higher permeability rocks (RT 1). The reservoir is very stratified, and the correlation length of the rock types has to be very much greater than the well spacing.
The wells are all hydraulically fractured and thus the flow is generally horizontal into the fractures and from the fractures into the well.
The fracture extends from the top to the bottom of each stratigraphic unit that the fracture encounters. If a fracture only partially penetrates a stratigraphic unit, this method may not work.
The gas is relatively dry and thus the flow is less affected by gravity than for reservoirs containg flowing liquids.
The reservoir is made up of rock with a wide range of permeability, but the flow is dominated by the well connected, higher permeability rocks (RT 1).
The reservoir is very stratified, and the correlation length of the rock types has to be very much greater than the well spacing.
Re-ordering of the RTs in a given upscaling method will result in acceptable accurate estimates of hydrocarbon recovery, compared to the fine grid model. It showed that the order of layering did not matter for the area studied, because a conductive fracture connects all the layers. This method probably really is only applicable for dry gas reservoirs (where gravity is not important) and in fractured wells (where horizontal flow into the fractures and into wells dominates). In oil reservoirs and rich condensate reservoirs where gravity is an important factor, the ordering of the rock types within the simulation layer may matter.
It will also be shown that an approximately 90% reduction in the simulation modelling computing time could be achieved if the appropriate upscaling technique is used. To achieve this reduction in computing time, some compromises were made, including assuming RT 4 is non-pay in upscaled models where RTs 4 & 5 are grouped together in the same simulation layers, resulting in reduction of HCPV. It is important to mention that some RT 5 zones in the log have thin instances of other rock types, which are not accounted for in the upscaled models and could result in an error in average pore volume preservation.
Britt, L. K. (NSI Fracturing, LLC) | Otzen, G. (ENAP) | Guzman, M. (ENAP) | Kusanovic, G. (ENAP) | Alqatrani, G. (Missouri University of Science and Technology) | Dunn-Norman, S. (Missouri University of Science and Technology)
The Glauconite Formation in southern Chile is an unconventional resource made up of approximately forty percent clay and glauconite, thirty-four percent feldspar, twenty-three percent quartz, and three percent tuff. Like many unconventional reservoirs outside the United States, establishing commercial production from the Glauconite Formation was difficult given the make-up of the reservoir, the availability of equipment and materials, and the logistics associated with drilling, completing, and fracture stimulating wells in a remote area like Tierra del Fuego in southern Chile.
This paper describes the effort to establish commercial production from the Glauconite Formation beginning with a couple of marginal wells in late 2011 through a nearly seventy-five well development by early 2016. As part of this effort, a basis of fracture design was established by developing a profile with depth of in-situ stress, Young's Modulus, and leak-off coefficient. These geomechanical assumptions were then tested and modified with core and pump-in data and used to make revisions to the fracture stimulation design. The designs were optimized to ensure that the critical fracture dimensions (fracture length, conductivity, and height) were achieved to maximize well performance.
Next, a data collection plan was developed to capture key information about completions, mini-frac analysis, fracture design and execution, fluid, proppant, and chemical additives, reservoir quality, and post fracture flowback and clean-up data. The database was then utilized to monitor the Glauconite fracture stimulation program to ensure that the basis of design for the fracture program maintains viability and to ensure that the appropriate equipment and materials were mobilized for fracture optimization and to meet the program objectives.
This paper focuses on the key elements of well completions and fracture stimulation practices as they apply to tight gas and unconventional formations by using the database to manage project risks and develop appropriate mitigation strategies. For example, preliminary fracture stimulation designs were based on initial reservoir permeability estimates of 4 md, however, the data collection plan incorporated a well test program which determined that the actual reservoir permeability was nearly one thousand times less.
Another example was the rock mechanics and geomechanical data derived from dipole sonic logs indicated little in-situ stress contrast and raised concerns about the ability to achieve the desired fracture dimensions. In addition, the log derived Young's Modulus was low and inconsistent with the core tri-axial compression and ultrasonic data as well as the on-site mini-frac net pressure data. As a result, a number of tri-axial compression tests were conducted and it was determined that the Young's Modulus was much higher than indicated from the logs. The collected data and monitoring program resulted in significant treatment modifications ranging from the small cross-linked stimulations conducted initially to linear gel, hybrids, and ultimately treated water fracture stimulations as equipment and materials became available. This work is beneficial as it:
Conducts an indepth well analysis and evaluation to develop a basis of fracture design, Builds a database of important reservoir quality, completion, mini-frac, fracture, and post fracture clean-up data, Utilizes the database to monitor the fracture design basis, manage material and equipment needs in a remote area, and to maximize well performance.
Conducts an indepth well analysis and evaluation to develop a basis of fracture design,
Builds a database of important reservoir quality, completion, mini-frac, fracture, and post fracture clean-up data,
Utilizes the database to monitor the fracture design basis, manage material and equipment needs in a remote area, and to maximize well performance.