Well interference in unconventional CBM reservoirs is often desired. It reduces reservoir pressure; significantly increasing gas production through desorption. However, identifying interference between wells and extracting quantitative reservoir information using production data analysis is a challenge. The primary objectives of this study are to identify production characteristics of interfering CBM wells, evaluate reservoir parameters, demonstrate the application of interference data using field examples to predict well performance and develop guidelines to optimize geospatial well-pattern.
A field wide interference study has been undertaken to track changes in gas rate, water rate, wellhead pressure and fluid level in each well. An ‘event-based’ filter is applied to the dataset to correlate production behaviour of a well with any unplanned ‘event’ in its offset well. Planned well tests are then conducted to ascertain these evidences of interference. Using production data analysis of interfering wells, a set of semi-analytical correlations have been developed based on the transient drainage radius model to determine production-governing permeability of coal formation, and also quantify the flow contribution of natural fractures and reservoir matrix.
Preliminary analysis of the study demonstrates several forms of interference. Well specific field examples have been presented for each case. Interference between producing wells having long production history show a trend reversal in gas flow rate due to additional dewatering support by its offset well. Similar behaviour is observed in the production characteristics of an old producer when a new well is drilled in a nearby location. However, effects of interference are more dominant when a well stimulation activity (fracturing or re-fracturing) is carried out in an offset well. During stimulation activity, offset wells show an abnormal decline in gas rate and wellhead pressure due to fracking fluid (water) load up in the reservoir. Conversely, a significant positive impact is seen in gas rate of both wells after the well is put back on production due to improved water production rate in the stimulated well. Permeability calculations show that natural and artificial fractures dominate production behaviour of CBM wells. The study also presents results of various simulated geo-spatial well patterns. Furthermore, it is shown that planned interference at an early time with an economically designed well spacing can maximize the production NPV of an asset for an operator.
The optimal well spacing to maintain and/or increase gas production with the right amount of resources is critical for maximised returns. This result of this study can be used as foundation to help operators optimize multi-well pad and future infill well development program based on the assessment of short-term and long-term recovery targets.
The accurate makeup of Rotary Shouldered Connections (RSC) is a critical step in optimizing the connection lifetime under complex downhole conditions. The makeup torque value of RSC depends on the friction coefficient of the assembly and the lubricant, which cannot normally be individually measured or determined, so that the API RP7G gives a recommended makeup torque based upon an assumed, yet constant, friction coefficient while a certain safety margin is considered. Therefore, the field induced stress state of the connection may differ from the connection optimum torque under reference conditions. This will lead to the following consequences: the lifetime of each connection is not maximized based on its drillstring position and the torque and axial force that can be transferred through the connection is different from the technical maximum limit.
Due to the technological development, a wide spectrum of power tongs can accommodate the increasing interest in mechanized operations at the rig floor today. The importance of a torque-turn recording was stated in many papers as a good control method of the makeup process, especially for casing running applications. However, we believe that the reliability of a drill string can be improved by using feed back of torque turn recordings. State-of-the-art devices not only allow the precise mechanized makeup of connections, but they also provide sufficient data to analyze the quality of the connection make-up. The motivation behind the research is the desire to make use of the data that is already provided for the benefit of increased lifetime of the connections and the reduction of drill string failures, especially for drilling under extreme downhole conditions like long horizontal, HPHT or deep water.
This paper presents a short overview of the state-of-the-art of current technology followed by a discussion of how technological advances can be used to improve the drill string reliability. Also, the readers are challenged to find the answer to the title question: "Do we need an Intelligent Makeup Solution for Rotary Shouldered Connections?"
Baker Hughes drilled one horizontal well for major Indian operating company in a, low resistivity contrast field, onshore India. The candidate field / basin is a proved petroliferous basin, located in the northeastern corner of India.
The scope of work for this project involved integrating geological and open hole offset parameters to build a Geosteering model. Integrated data included a study of offset well data from the field, regional and local dip analysis from wellbore images, and a review of structural maps. Successful integration of these data helped to steer the well in the desired zone as per plan and make the best use of the data and to reduce uncertainties in Geosteering, drilling. Although high-quality 16-sector images commonly yield bedding dip, fracture and other geological information, this paper emphasizes how real-time reservoir navigation decisions was made using Geosteering modelling, real-time image processing, dip picking study etc.
Unconventional oil and gas reservoirs are being explored significantly around the globe nowadays. The economical production of hydrocarbons from these unconventional oil and gas reservoirs like CBM requires very advanced and cost effective technologies. Hydraulic fracturing is such a technology which is being used in the oil and gas industry for many decades to create highly conductive channels in the formations having very low permeability values. Multistage hydraulic fracturing has been proved to be a great achievement in oil and gas industry to enhance the production from unconventional reservoirs. An effective hydraulic fracturing planning & execution is a key to achieve the expected results in terms of production from unconventional reservoirs such as tight gas, shale gas, coal bed methane or other very low permeability reservoirs.
Unconventional reservoirs such as Shale & CBM require large scale hydraulic fracturing operations, where multiple frac fleets, wire-line units, coiled tubing units; work-over rigs & ancillary services are mobilized. A scheduling software based project management approach was followed at CBM Raniganj for planning & modeling of operations. This paper aims to study how the operational resource deployed in Raniganj field for hydraulic fracturing was optimized in terms of time, cost & load for fracturing operations.
The approach of modeling & planning the hydraulic fracturing operations is based on project management & scheduling software. Assumptions were finalized based on experience. The loopholes, possible schedule slippages and other deterrents which could cause a lag in the hydro fracturing campaign aimed to pump over 1,600 frac jobs in CBM Raniganj field, over a period of 30 rig months, were identified clearly. The scope, time, budget & quality standards were clearly defined and a schedule was prepared with the help of the scheduling software to run the fleets in a clockwork manner. Activities like perforation, Acidizing, data fracturing, main fracturing, flowback, sand plug and finally sand cleanout were defined as series & simultaneous operation.
Barmer Hill Turbidites (BHT) are low permeability reservoirs in the Vijaya & Vandana field with an approximate in place reserve of a billion barrels. The field was discovered in 2004 with the discovery wells V-1 and V-2 respectively. Post drilling and completion these wells were tested without any stimulation technique, resulting in ~ 25 – 50 BOPD flow owing to tight nature of these formations. Subsequently the zones were hydraulically fractured and tested resulting in ~ 10 – 12 folds increase in the production rate of the oil. Also, the testing of multiple stacked reservoirs in these two wells further confirmed BHT-10 to be the most prolific zone in terms of commercial flow rates achievable. Apart from being tight formations, the low net to gross on reservoirs (<20%) further added to the challenges of devising a strategy to make these reservoirs flow at sustained commercial oil rates. Hence, when the field was taken for the next stage of a hydrocarbon field lifecycle i.e. the appraisal campaign, two very clear objectives were identified for achieving a successful appraisal campaign viz. hydraulically frac and test two of the existing wells in the field while aiming to connect the maximum available KH and ensure effective data acquisition through injection tests and temperature logs with an aim to calibrate the existing stress logs and eventually build a robust frac model.
The dynamic geo-mechanical parameters i.e. Young’s Modulus and Poisson’s Ration were calculated from the open hole sonic logs and were converted to static data using the lab measured value from the core tests. Stress logs generated from these static data points were used for the initial frac designing in the wells. During the execution phase of the frac campaign, at every opportunity available, injection tests were carried out and fall off data were acquired to estimate the closure pressures actually observed in these zones. Post acquiring the measured stress data, the earlier calculated stress logs were calibrated using these measured closure points (frac gradients) by incorporating the stress components due to strain factors (ɛmin & ɛmax) in both max and min direction of the principle stresses.
Post every data injection, temperature logs were also acquired. This gave a better control on frac height (hydraulic height) based on the cool downs observed on the temperature logs. This proved to be a very important data set in comparing the height predicted by the calibrated stress logs versus the height estimated from the temperature log cool downs. This step helped in gaining confidence on the model predictability. This also helped in real time frac design optimization and placement of perforation intervals for the main frac designs. Further, the entire model calibration exercise also helped in arriving at a porosity based leak off equation.
The paper endeavors to discuss in detail the entire workflow used during this appraisal campaign to arrive at a calibrated and a robust frac model whilst showcasing the journey taken from 50 BOPD to 500 BOPD in these tight oil sands to achieve ~ 10 fold production increase. Authors, further, emphasize on the importance of carrying out such data acquisitions during the appraisal phase of a field to gain better control on the models. This paper will also elaborate on the strategy deployed for these data acquisition to optimize the fracs in real time and to integrate different data sets for calibrating the geo-mechanical and frac simulation models.
Inyang, Ubong (Halliburton) | Cortez-Montalvo, Janette (Halliburton) | Dusterhoft, Ron (Halliburton) | Apostolopoulou, Maria (University College London) | Striolo, Alberto (University College London) | Stamatakis, Michail (University College London)
Estimating the effective permeability and microfracture (MF) conductivity for unconventional reservoirs can be challenging; however, a new method for estimating using a stochastic approach is discussed. This new analysis method estimates matrix permeability and the unpropped and propped MF conductivities during laboratory testing where MFs were propped with ultrafine particles (UFPs).
Kinetic Monte Carlo (KMC) simulations form the basis of the method used to estimate effective permeability of the core sample. First, the stochastic model was implemented to calculate effective matrix permeability of a small core taken from unfractured Eagle Ford and Marcellus formation samples using scanning electron microscopy (SEM) images and adsorption data to obtain the pore-size distribution (PSD) within the sample. The KMC approach then evaluated the effect of various parameters influencing the conductivity of laboratory-created MFs. Case studies considered for this work investigate the conductivity improvement of a manmade MF as a function of the UFPs used as proppants that maintain width under high stress, the UFP (proppant) concentration, and the UFP flow perpendicular into a secondary or adjacent MF zone (2ndMF) penetrating the face of an opened MF during flow testing under stress. The leakoff area widths considered were 1, 2, and 3 mm and can be propped or unpropped.
Results obtained for the unfractured Eagle Ford and Marcellus samples closely correlate with other computational and experimental data available. For the laboratory-prepared nonpropped and propped MF samples, the effective propped width was determined to have the greatest effect on the MF conductivity, which increased by two orders of magnitude in the presence of the UFPs. The remaining two factors—proppant concentration and length of 2ndMFs—helped improve the effective MF conductivity in a linear manner; the highest proppant concentration and the 2ndMF zone resulted in the highest fracture conductivity achieved. Insight obtained from this study can be used to optimize fracturing designs by including UFPs and to create strategies for maximizing hydrocarbon recovery during development of unconventional resources where MFs are opened during stimulation treatments.
Shale plays are anisotropic in terms of their reservoir quality which gets reflected in their productivity. Reservoir qualities like organic richness, thermal maturity, hydrocarbon saturation, the volume of clay, brittleness and pressure affect the productivity of the shale plays. In general, the volume of clay has a negative relationship whereas other parameters listed above have a positive relationship with production. In our study area, we found the deepest wells despite having better rock quality; do not perform like nearby shallower wells. The objective of this study is to understand the not so obvious reason behind underperformance of these deepest wells.
Since the wells are located at a deeper depth and the reservoir temperature is high (90 to 135°C), so we studied the area from clay diagenesis and fluid expansion perspective. We have reviewed the imprints of clay diagenesis with the help of XRD data and core integrated multi min processed wireline logs. We observed an increasing trend of illite, chlorite towards the deeper part of the reservoir along with a decreasing trend of smectite in the same direction which indicates a higher degree of clay diagenesis. Fluid expansion study is carried out with the help of total organic carbon and hydrocarbon saturation. This study indicated a higher degree of fluid expansion (TOC to hydrocarbon generation) in the deepest part.
Subsequently, 1D pore pressure, stress and rock mechanical modeling is carried out to evaluate the effect of a higher degree of diagenesis and fluid expansion on geomechanical parameters (pore pressure, stress and brittleness). 1D modeling reveals that the deeper wells have abnormal pressure, stress and low brittleness, which is primarily due to extra pressure contribution from fluid expansion and clay diagenesis apart from the compaction disequilibrium process. This abnormal stress and reduction in brittlness likely to have created challenges for the applied hydrofrac job in the deepest part resulting to narrow frac geometry. Comparison of hydraulic fracture modeling between a shallow and the deepest wells reveal that the hydraulic fracture geometry in the deepest well is narrower than the shallower well. So we came to the conclusion that the deepest wells are underperforming than the shallower wells despite of their better rock quality due to ineffective fracturing and comparatively narrower fracture geometry.
The impact of clay diagenesis and fluid expansion in shale productivity has not been studied widely. Though many authors have extensively studied the impact of clay diagenesis on permeability and pore pressure, the integration of shale well production is rarely attempted. This work will help the operators to better analyze and understand their shale reservoir from clay diagenesis and fluid expansion point of view before planning the hydrofrac jobs.
Yang, Zhaopeng (PetroChina Research Institute of Petroleum Exploration&Development) | Li, Xingmin (PetroChina Research Institute of Petroleum Exploration&Development) | Chen, Heping (PetroChina Research Institute of Petroleum Exploration&Development) | Ramachandran, Hariharan (The University of Texas at Austin, Hildebrand Department of Petroleum and Geosystems Engineering) | Shen, Yang (PetroChina Research Institute of Petroleum Exploration&Development) | Yang, Heng (China National Oil and Gas Exploration and Development Corporation) | Shen, Zhijun (China National Oil and Gas Exploration and Development Corporation) | Nong, Gong (China National Oil and Gas Exploration and Development Corporation)
The block M as a foamy extra-heavy oil field in the Carabobo Area, the eastern Orinoco Belt, has been exploited by foamy oil cold production utilizing horizontal wells. The early producing area has been put into production about 10 years, existing problems of productivity declining and produced gas-oil ratio rising. Therefore, the development optimization for the early producing area should be conducted in order to obtain the more profitable oil recovery. A typical foamy oil reservoir simulation model using 5 components was created to understand the remaining oil distribution features. Based on above understandings, technical strategies were proposed for infilling well deployment in the early producing area. Results show that the gravity drainage and gravity differentiation of oil and gas during the cold production of foamy extra-heavy oil from horizontal wells by foam flooding are the main mechanisms for formation of remaining oil. And the influence factors of remaining oil distribution include horizontal well spacing, reservoir thickness, reservoir heterogeneity, interlayer distribution and reservoir rhythm. Thus tor foamy extra-heavy oil CHOP process, the enriched remaining oil area is the place between two adjacent horizontal wells with well spacing of 600m. Therefore, well infilling is an effective measure improving oil recovery factor of cold production, and the well infilling should be implemented as soon as possible to obtain better performance of cold production.
This paper evaluates the impact of decision making and uncertainty associated with production forecast for 2000+ wells completed in Permian basin. Existing studies show that unconventional reservoirs have complex reservoir characteristics making traditional methods for ultimate recovery estimation insufficient. Based on these limitations, uncertainty is increased during the estimation of reservoir properties, reserve quantification and, evaluation of economic viability. Thus, it is necessary to determine and recommend favorable conditions in which these reservoirs are developed.
In this study, cumulative production is predicted using four different decline curve analysis (DCA) − power law exponential, stretched exponential, extended exponential and Duong models. A comparison between the predicted cumulative production from the models using a subset of historical data (0-3months) and actual production data observed over the same time period determines the accuracy of DCA's; repeating the evaluation for subsequent time intervals (0-6 months, 0-9 months,) provides a basis to monitor the performance of each DCA with time. Moreover, the best predictive models as a combination of DCA's predictions is determined via multivariate regression. Afterwards, uncertainty due to prediction errors excluding any bias is estimated and expected disappointment (ED) is calculated using probability density function on the results obtained.
In this paper, uncertainty is estimated from the plot of ED versus time for all wells considered. ED drops for wells having longer production history as more data are used for estimation. Also, the surprise/disappointment an operator experiences when using various DCA methods is estimated for each scenario. However, it appears that whilst Duong (DNG) method always overpredicts, power law exponential (PLE) decline mostly under predicts, the stretched exponential lies between DNG & PLE estimates and the extended exponential DCA demonstrates an erratic behavior crossing over the actual trend multiple times with time. In conclusion, profitability zones for producing oil in the Permian basin are defined implicitly based on drilling and completion practices which paves the path to determine the "sweet spot" via optimization of fracture spacing and horizontal length in the wells.
The outcome of the paper helps improve the industry's take on uncertainty analysis in production forecast, especially the concept of expected disappointment/surprise. This study suggests that effects of
The booming of shale gas production has affected the natural gas price in the United States (U.S). Natural gas price has plummeted due to the excessive capacity. On the other hand, the import of crude oil and its production of diesel, gasoline, and others are increasing. The problem lies in finding a practical, economical and efficient way of making natural gas marketable. A potential solution is Small-scale Gas-to-Liquids plants. Small-scale GTL can fulfill some of the petroleum products demand such as Gasoline, Ultra-low-sulfur diesel, and jet-fuel. Small-scale GTL plants especially can benefit countries where the gas production is higher than gas demand, yet these countries depend on imported oil.
A Monte Carlo simulation approach is used to conduct sensitivity analysis on various parameters such as the feedstock/natural gas price, plant capacity, plant efficiency, capital expenditure (CAPEX), operational expenditure (OPEX), and products selling prices. The range for natural gas prices and gasoline prices are obtained from average historical data in the United States for the past five (10) years where the shale gas production is booming. The CAPEX is attained from previous GTL project plants before using the Power-Sizing model and literature. The annual OPEX is the percentage fraction of the CAPEX. The plant capacity was chosen based on the diseconomy factor estimated from previous GTL projects. Even with the premium quality of GTL products, the selling price for the products is equal to regular crude oil products.
Economic metrics such as Net Present Value (NPV), Internal Rate of Return (IRR), Cost-to-Profit (C/P) ratio and Payback Period were used to assess the success of GTL technology at each given business case. Results showed that NPV, IRR, C/P ratio and payback period are most affected by CAPEX, products selling price, OPEX, and capacity of the plant, in respected order. Based on these case scenarios and parameters, sensitivity analysis is conducted using Monte Carlo's simulation of 10,000 iterations the results for NPV, IRR, C/P ratio and payback period showed that the GTL project is profitable. The NPVs for the GTL plant in this study are positive for all case scenarios.
It is expected that the outcome of this research would guide shale gas producers and private investors when considering GTL investment to monetize their assets in the United States and beyond.