Hole cleaning evaluation and prediction presents a challenge in drilling industry. The optimization of hole cleaning can reduce the down time during drilling operations. Good hole cleaning means high rate of penetration and less drilling problems. In this paper, a robust hole cleaning model is presented. It is based on monitoring and controlling simultaneously the carrying capacity index (CCI) and the cuttings concentration in the annulus (CCA) to ensure perfect hole cleaning. The cost of drilling can increase tremendously if not enough attention is paid to ensure proper hole cleaning. The knowledge of the size of cuttings, size of annulus, flow pattern, and down hole fluid properties cannot be determined with high level of accuracy using hole cleaning indicators such as transport ratio, hole cleaning ratio or transport index. Cutting concentration in annulus (CCA) alone cannot reveal the drilling mud properties, while the application of CCI alone will not help in optimizing ROP to the desired limit. The drilling parameters and mud rheological properties in certain hole sections were collected and analyzed first to determine the effect of mud properties and drilling parameters on hole cleaning and ROP performance. The data selected are from the same hole size, formation type and mud type. The relationship between mud rheological properties and CCI was then evaluated to determine how strong they are. This step helps determine the significance of mud rheological properties on estimating CCI. CCI and CCA were then simultaneously monitored and controlled to ensure proper hole cleaning leading to optimization of the Drilling operations and reduction in the drilling time. The data analysis demonstrated a strong link between rheological parameters and CCI. The approach was then validated by trial testing it in the field. The results showed that efficient hole cleaning level was achieved, which facilitated improvement of rate of penetration. It was used to drill in challenging hole sections and improved the well drilling performance by more than 55%, mitigated stuck pipe incidents, and eliminated wiper trips, reaming trips, and pumping of sweeps. The new approach or hole cleaning model showed the importance of combining CCI and CCA to optimize the drilling operations and reduce the time. This is the first time to combine the two techniques for hole cleaning optimization. The new hole cleaning model will help the drilling engineers drill a clean, stable hole in short time, and hence reduce the total cost of the drilling operations.
Energized fluids are defined as fluids with one or more compressible gas components, such as CO2, N2, or any combination of gases, dispersed in a small volume of liquid. Generally, these fluids offer an attractive alternative to conventional stimulation fluids in many cases such as low reservoir pressure, water-sensitive formations, and/or the need for shorten flowback period. Energized fluids have many challenges such as low stability at high temperature, high friction pressure during pumping, corrosion in the case of using CO2, and the need for specialized surface pumping equipment. The objective of this paper is to describe the typical components of energized fluids and their effect on the fluid performance. Also, lab testing methods used to evaluate energized fluids performance will be discussed in detail.
Foam is a class of energized fluid used for different applications including acidizing, hydraulic fracturing, and fluid diversion. For each application, foam should have a minimum acceptable value of viscosity, stability, and/or fluid compatibility. Those values were reviewed from literature and categorized based on reservoir conditions. Also, different rheological models are analyzed to understand foam flow behavior in both tubing and porous media. Finally, the mechanism of foam transport in porous media is reviewed in this report, which gives insight into foam stability and propagation.
The most common application of nitrogen is in artificial lifting, while supercritical CO2 is proposed for condensate banking removal. Selection of the right surfactant, like alpha olefin sulfonates, which are thermally more stable than alkyl ether sulfates, is crucial while designing foam treatment, as they produce the most persistent foams at high salinity and elevated temperatures in the presence of synthetic and crude oils. Currently available foam-based fracturing fluid systems in the industry have temperature limitations to 300°F. The crosslinked gelled foam has a better temperature range than the viscoelastic foam fluid system, whereas non-crosslinked biopolymer-based foam fluid showed better proppant pack cleanup characteristics. In a recent report, the addition of 0.1% silica nanoparticles along with cationic surfactant was shown to enhance CO2 foam stability by 13 hours. In this review, all these aspects of energized fluids are well reported from literature.
In this paper, we discuss findings from different lab testing and field demonstration of energized fluids. Compositional modelling for hydraulic fracturing with energized fluids is also reviewed to add insight on fracture geometry estimation. This paper provides guidelines and recommendations for selecting the right energized fluids for successful stimulation treatment.
Al-Hameedi, Abo Taleb T. (Missouri University of Science and Technology) | Alkinani, Husam H. (Missouri University of Science and Technology) | Dunn-Norman, Shari (Missouri University of Science and Technology) | Flori, Ralph E. (Missouri University of Science and Technology) | Hilgedick, Steven A. (Missouri University of Science and Technology) | Alkhamis, Mohammed M. (Missouri University of Science and Technology) | Alshawi, Yousif Q. (Basra Oil Company) | Al-Maliki, Madhi A. (Basra Oil Company) | Alsaba, Mortadha T. (Australian College of Kuwait)
Wells drilled in the Rumaila field are highly susceptible to lost circulation problems when drilling through the Hartha formation. This paper presents a comprehensive statistical work and sensitivity analysis models of the lost circulation events for more than 300 wells. Moreover, this study will demonstrate an integrated analysis regarding the most significant drilling parameters, which have a pivotal impact on the lost circulation to provide the greatest chance of mitigating or avoiding lost circulation in the Hartha formation.
Lost circulation events are extracted from daily drilling reports, final reports, and technical reports. Key drilling parameters are analyzed using statistical software to understand the relationship between the mud losses and various drilling parameters such as MW, ECD, Yp, ROP, SPM, RPM, WOB, flow rate, and bit nozzles. The sensitivity analysis is conducted to examine the impact of each parameter in all models. In addition, variance inflation factor (VIF) method is used to test for the multicollinearity phenomena in each model to maximize the accuracy and to obtain a solid mathematical model.
The volume loss model is conducted to predict lost circulation in the Hartha formation. As a proactive action, this model can be used to estimate the volume loss prior drilling the Hartha formation. Observations that have been made from the volume loss model are MW, ECD, and Yp have a significant impact on lost circulation respectively; however, SPM, RPM, and ROP have a minor effect on the volume loss model. Equivalent circulation density (ECD) model is obtained to estimate ECD in the Hartha formation, and from this model can be deduced that MW, ROP, and Q have a significant impact on ECD respectively; nevertheless, RPM and Yp have a minor impact on the ECD. The rate of penetration model is made to estimate ROP in the Hatha formation. It is concluded that WOB, SPM, and RPM have a significant impact on the ROP respectively, but MW, ECD, and Yp have a minor influence on the ROP. In addition, engineering solutions are developed to give a clear image regarding lost circulation, and it will provide a unique statistical study and coherent sensitivity analysis of all factors which have an essential or a small impact on this issue.
Due to the lack of published studies for this formation, this study will provide a unique understanding for lost circulation events, drilling fluid properties, and operational drilling parameters, which have a prominent or a minor impact on the mud losses issue. Lost circulation will be illustrated in terms of causes, consequences, recommendations, and guidelines to reduce or avoid unwanted losses. In addition, this work can serve as a practical resource for drilling through the Hartha formation.
Liu, Shuangshuang (PetroChina) | Wei, Chenji (PetroChina) | Gao, Yan (PetroChina) | Li, Yong (PetroChina) | Luo, Hong (PetroChina) | Liu, Zhuo (PetroChina) | Xiong, Lihui (PetroChina) | Zheng, Jie (PetroChina) | Lou, Yuankeli (PetroChina)
The Middle East carbonate reservoirs are mostly reef flat sedimentary complexes, which are high heterogeneous and have extensive baffles. It brings great challenges to the efficient development of such reservoirs. Focus on the problem, a method of describing baffle distribution conjunctively using static and dynamic data is put forward in this paper. The distribution of baffles in the target formation is characterized based on core observation, well loggings, image logs, etc. Then, their impact towards reservoir performance is evaluated based on production data and dynamic surveillance data. Based on the study, it is acquired that cementation mainly controlled the upper baffles and compaction controlled the lower. Generally speaking, permeability of baffle is higher in the crest area and lower in the flank area. Baffles are stably distributed throughout the reservoir, although their ability to block fluid flow varies from region to region. The existence of baffles and their ability to block fluid flow had impact to the development effect, so development optimization and scheme comparison carried out. The corresponding development strategies are proposed for reservoirs with extensive baffles. Injectors and producers with highly-deviated well-type will help establish effective displacement system and achieve better reservoir production, it can improve the development effect and enhance oil recovery. This study offers a comprehensive case study for engineers and geologists to better understand this reservoir, it also provides a methodology that can be referred when developing similar fields.
Carbonate reservoirs accounted for about 40% of the world's total oil and gas reserves, and oil and gas production accounted for about 60% of the total output [Roehl P O et al. 1985]. About 80% of the oilbearing formations in the Middle East are carbonate rocks, and the oil and gas production accounts for nearly 2/3 of the world output [Alsharhan A S et al. 1997]. Carbonate reservoirs contain more than 50% of the world's conventional oil and gas reserves, and generally have relatively low recovery rates [S.K.Masalmeh et al. 2012].
Carbonate reservoir types are diverse, and different types of reservoirs have great difference in permeability characteristics [Zhang Ningning et al. 2014]. The carbonate reservoirs in China mainly include fractures and fractured-cavity carbonates, the displacement mechanism of which is mainly carried out on the fractured-cavity media [Jin Zhijun et al. 2010, Liu Xiao-lei et al. 2017]. The large-scale carbonate reservoir in the Middle East is mailly reef-flat sedimentary complex, and the distribution of reservoir properties in the plane and in the vertical direction is very complicated [Bai Guoping 2007]. The heterogeneity is serious in lithology, physical property and reservoir scale [Jia Ailin et al. 2013]. The baffles are non-permeable or low-permeability layer sandwiched between the smallest cells in which the regional contrast can be performed [Cui Jian et al. 2013]. The existence of baffles strengthens the heterogeneity of the reservoir and makes the relationship between oil and water movement complex and changeable, which is one of the main factors affecting the reservoir development effect [Han Rubing et al. 2014].
Smith, Robert (Geophysics Technology, EXPEC Advanced Research Center) | Bakulin, Andrey (Geophysics Technology, EXPEC Advanced Research Center) | Jervis, Mike (Geophysics Technology, EXPEC Advanced Research Center) | Hemyari, Emad (Geophysics Technology, EXPEC Advanced Research Center) | Alramadhan, Abdullah (Geophysics Technology, EXPEC Advanced Research Center) | Erickson, Kevin (Geophysics Technology, EXPEC Advanced Research Center)
Saudi Aramco recently started the company's first CO2-EOR demonstration project in an onshore carbonate reservoir. Time-lapse (4D) seismic has proven to be a valuable reservoir management tool for monitoring the areal expansion of CO2 plumes in many similar projects around the world. However, the complex and dynamic nature of the near surface encountered in the desert environments of the Middle East results in high levels of 4D noise. This noise, coupled with the weak 4D signal expected from injection into a stiff carbonate reservoir, makes mapping the time lapse signal very challenging. The objective of this project was to develop a highly repeatable system capable of detecting small reservoir changes related to CO2 injection to enable the plume expansion to be tracked over time.
Achieving highly repeatable seismic data requires specialized seismic acquisition and dedicated processing. A novel acquisition system using buried receivers was adopted to reduce 4D noise resulting from near-surface variations. To minimize the non-repeatability inherent in using surface sources, a differential GPS guidance system was implemented to ensure high positioning accuracy. Even with these acquisition efforts, a fit-for-purpose 4D processing workflow was necessary to further reduce differences between surveys.
Despite the challenges faced, outstanding data repeatability has been achieved, with mean NRMS values of less than 5% for data acquired during the same season. This level of repeatability is comparable to data acquired in marine 4D surveys and has resulted in the detection of the small 4D signal caused by CO2 injection. Frequent monitor surveys, with one full survey acquired every four weeks, shows the CO2 plume growing over time with increasing injection volume. While the observed CO2 plume largely correlates to available engineering data, discrepancies have been identified when compared with the predicted seismic response based on the reservoir simulation model. This indicates that 4D seismic can be used to constrain the reservoir model, yielding a better history match and improved predictions to enable more informed engineering decisions to be made.
This is the first successful application of seismic monitoring of a carbonate reservoir in an area renowned for poor seismic data quality. To overcome the challenges, a novel hybrid acquisition system using buried sensors and surface sources was developed. Advances in the seismic processing workflow were also required to bring the 4D noise down to a level that enabled detection of the CO2 injection.
Deep gas drilling in middle east is very challenging and this becomes even a bigger challenge when the wells are drilled horizontally and in 5 7/8” hole size. Two types of rocks are drilled across different field. First one is khuff formation in upper Permian and second is Unayzah formation in lower Permian. Both formation have different challenges, this paper is focused on optimization in Khuff reservoir where the service provider is involved. Deep gas drilling optimization was based adding new technical experts and peer reviewing the learning in place and implementing the new best practices. Historically plenty of efforts were made for performance improvement, however still there was and is room for continuous improvement. All the efforts were based on the implementation technologies, pushing the technology to limit, improving the knowledge of drilling environment and continuous changes in the drilling strategies. After reviewing the following changes were recommended and are in place across different fields
After implementation, ratio for number of wells have been drilled in one run is increasing. Drilling parameters implementation has resulted in consistent ROP and BHA optimization has resulted in reduction in LIH year on year.
5-7/8” Horizontal Laterals of deep gas wells have been drilled in upper Permian Khuff formation by the operator. However, high frequency of stuck pipe and lost in hole (LIH) incidents, long well delivery time and high tools failure rate greatly affacted both the operator and the service companies’ performance. As a major service provider, responding to the request of the operator, Schlumberger initiated a drilling optimization compaign to improve the operation efficiency, reduce the stuck pipe and LIH incidents, reduce downhole tool failures and eventually reduce the well delivery time, nonproductive time and the cost of the well.
Polyacrylamide-type polymers are widely used in polymer flooding techniques for mobility control. To monitor the performance of a polymer flooding process in either field application or laboratory testing, it requires the accurate determination of polymer concentrations in the effluents. This paper presents a robust nitrogen-digestion method to determine the concentrations of various types of polymers such as hydrolyzed polyacrylamides, sulfonated polyacrylamides and cationic polyacrylamides.
Different from the classical nitrogen-bromination method used to identify polymer concentrations, the nitrogen-digestion method is based on the digestion of amide groups in the polymers as free nitrate ions using digestion device operated at 120°C. The resultant solutions were measured by a visible light spectrophotometer. The nitrogen contents as measured by absorbance values of the solutions are used for the calculation of the polymer concentrations. The average testing time for each sample is less than 5 minutes.
Seven polymer samples from three different polymer types were investigated. The experimental results show good correlations between nitrogen content and absorbance values and the resulting concentration for each polymer sample studied. As the chemical structures of polymers might be altered in the application process, such as hydrolysis of amide groups to hydroxyl groups, the concentration results obtained could be interfered with. Therefore, the infrared (IR) method was used to revise the concentrations obtained by nitrogen-digestion method. A normalized correlation as a rule-of-thumb was set up to categorize the polymer type and determine the polymer concentration. In addition, it was also noted that the measurements of polymer concentration using the nitrogen digestion method are not influenced by the salinities of make-up brines.
This paper presents an accurate, portable, and fast way to determine the polymer concentrations in brines. It is of particular importance for field operations.
Chemical enhanced oil recovery (EOR) technologies have been extensively studied and widely applied in sandstone and carbonate reservoirs for decades (Green and Willhite 1998, Han et al. 2013, Olajire 2014). Water-soluble polymer is used to increase the viscosity of injection water and control the water/oil mobility ratio, which enhances the oil recovery sweep efficiency, creates a smooth flood front without viscous fingering and decreases the residual oil saturation in place (Needham and Doe 1987, Morgan and McCormick 1990, Sheng et al. 2015). Polyacrylamide-type polymer is one of the most widely used water-soluble polymers in EOR technique (Argabright et al. 1982, Swiecinski et al. 2016).
Acid stimulation is an excellent method to increase hydrocarbon production and long-term formation drainage from carbonate formations. However, the stimulation effectiveness largely depends on pertinent placement method. Besides the necessity for optimized treatment design and fluid recipe, homogenous acid distribution is one of the most critical aspects for treatment success. For this purpose, a novel completion method has been deployed that allows for effective acid stimulation by maximizing formation contact in the openhole horizontal wellbore.
An improved Multistage Stimulation System (MSS) that has been developed to distribute acid homogenously across the lateral is utilized, where multiple sleeves are deployed in clusters as part of a single stage, and opened with a single size ball without being limited to pump rate. It was considered imperative to have positive indications of the balls landing on the seats and the sleeves being shifted open within the zone of interest. The previous MSS system was based on severing part of the nozzles for fluid access which needed to be upgraded for better operational efficiency and production enhancement.
The new completion technology is suitable for carbonate formations which are tight, heterogeneous and require stimulation to improve gas production and recovery. Wells drilled in the maximum horizontal stress direction to mitigate hole stability risks and geosteered to maximize the formation contact makes it difficult to stimulate effectively. Therefore, an improved MSS system is required to homogenously distribute the acid across the lateral during the stimulation. This novel MSS completion design was undertaken standardized, well established trial test procedure and was applied in a candidate well and included three stages where two of the stages utilized four sliding sleeves while the remaining stage was integrated with five sliding sleeves. Each stage was isolated by hydro-mechanical packers in the 5.875 in openhole.
Each stage was then monitored using a new surface mounted real-time downhole monitoring system, an electronic device that enables live verification of completion operation events while being independent of pressure. The data gathered from different sources indicated that the sleeves functioned as per design. The production results exceeded the expectations.
This paper describes a novel approach that enhances acid stimulation effectiveness and fulfills stimulation objectives using advanced openhole MSS completion technology. Evolution of the technology and comparison with its predecessor is discussed. It also demonstrates the use of a new surface monitoring system that supplies real time data during sleeve activations enabling clear and accurate detection of downhole events.
Tian, Changbing (PetroChina) | Lei, Zhengdong (PetroChina) | Zhu, Zhouyuan (China University of Petroleum) | Chen, Zhangxin (China University of Petroleum) | Li, Lei (PetroChina) | Wang, Wenhuan (PetroChina) | Peng, Huanhuan (PetroChina) | Tao, Zhen (PetroChina)
In this work, we implement new software for improved waterflood management by combining classical finite volume reservoir simulation together with streamline tracing and corresponding interwell flux evaluations to optimize waterflood performance. We show reduced water cut and improved oil recovery by using streamline-based flux information to adjust well rates, while retaining the advantages of rigorous finite volume simulation.
We have introduced two basic modules here: a commercial reservoir simulator Eclipse and our own streamline tracing and waterflood management program. Waterflood simulation is performed for a certain time span until simulation is paused and the streamline tracing program is called to calculate inter-well fluxes and adjust new well rates for better waterflood performance. The simulation continues afterwards until the next tracing and adjustment point is reached. The two modules work iteratively. The streamline tracing program uses the classical Pollock's tracing method. It is designed to trace streamlines on a compressible velocity field and a general corner point grid system with nonneighboring connections. The new injection rates are adjusted according to each well's injection efficiency calculated from inter-well fluxes as proposed in previous works.
Our waterflood management program successfully works cooperatively with the commercial simulator, with data transfer realized by making the simulator to output the velocity field and other information into restart files. Streamline tracing is performed successfully not only on simple geometry corner point grid cases, but also on heavily-faulted realistic reservoirs under waterflood. Streamline-based inter-well multi-phase fluxes are calculated, in which the injection efficiencies are derived accordingly. Injectors with higher efficiencies will receive more water from the source, according to the injection allocation algorithms and vice versa. After re-adjusting injection rates multiple times during the simulation, we typically observe a reduction in field water cut of up to 5% and an increase in oil recovery in our test cases. Inter-well flux information serves as effective diagnostic tools to identify injector-producer pairs with large amount of water cycling. All simulations conducted here are rigorously finite volume based, which takes into account the full physics of non-advective processes such as gravity and capillary effects.
In conclusion, we have implemented a streamline-based waterflood management program which works iteratively and cooperatively with a commercial reservoir simulator, without switching to streamline simulation. It provides an effective solution for improving oil recovery in brown fields by combining the rigorous mathematical nature of finite volume simulation and the power of streamline based flood management.
Hydraulic fracturing is more popular, due to its revolutionary impact in the US oil industry, especially in unconventional reservoirs. This paper first presents the analysis of hydraulic fracturing treatments in 56 vertical and horizontal wells in the Wolfcamp and Spraberry formations of the Permian Basin in West Texas. Intrinsic treatment strategies and operational methodologies used by different operators in the Basin were evaluated with the goal of extracting and deducing insights into criteria that characterizes operational virtuosity. The evaluation focused on: proppants types and amounts, fluid types and volumes, treatment rates, well productivity and treatment cost. The second part presents the application and integration of these best practice concepts in the re-designing of hydraulic fracture treatments in a case study well already stimulated with available treatment data.
Vertical wells were studied with 25 wells with over 150 treatments in both formations, 18 horizontal wells in the Spraberry formation with over 200 treatments, in Midland sub-basin and 13 horizontal wells in horizontal Wolfcamp in Delaware sub-basin. The Spraberry formation is very fine-grained sandstone, siltstone and carbonates with shales. The Wolfcamp is a complex formation divided into A, B, C and D, mostly limestone, with interbedded organic-rich siltstones. Empirical and statistical analysis using correlations and analysis of variance were used to identify and distill the best practices that actively and positively increase the production rates and decrease the production costs in each of these formation and well types. These results were then integrated in designing optimal hydraulic fracture treatments for these formations in the case well. Log analysis was done with industry standard software for accurate interpretation of the target formations and determination of rock mechanical properties used in the hydraulic fracture design software.
Mined data and analysis showed that operators merely replicate designs from similar wells and formations. This practice increases the errors, costs, and reduces expected productivity. Results show that the use of 20/40 white proppant is not economical, while the use of 40/70 white proppant is recommended in both formations. Crosslinked gel creates more complex and wider fractures, but it increases cost drastically, while slickwater was amenable to treatment costs and production rate, but more volume will be needed for the treatments, hence, the use of hybrid fluids are recommended. The original design used 20/40 white sand, the total stage cost of the treatment was 707,236. In the new treatment design, 40/70 white was used instead; all the scenarios evaluated gave a reduction in cost with $100,000.
These results are applicable in enhancing optimal hydraulic fracture treatment designs for these formations in the Permian Basin. Also, they serve as templates for other basins with similar formations. These results will be made better by continuous improvements with integration of field results.