Realtime Wellbore Digitalization for Stimulations Using Multi-Well Fiber Optics

Distributed Fiber-optic Sensing (DFOS) provides real-time data acquisition, monitoring and diagnostics for well stimulation and well spacing assessment. These include measurements of Distributed Acoustic Sensing (DAS) with high frequency acoustics in treatment wells, and low frequency strain/temperature sensing in offset monitor ones. The goal of this integrated study is to show the value of multi-well fiber sensing for real time fracturing diagnostics and stimulation optimization. By integrating near field injection to far field strain responses we assess overall reservoir development. The availability of fibers on both the treatment well and a nearby observation well allows us to investigate the near-wellbore injection profile and the far-field strain fracture propagation. Quantitative strain levels clearly respond to the effects of well distance, location and treatment well stimulation design. Monitoring well strain measurements of fracture density and triggered stimulated span were logged and compared to acoustic signals in the nearfield stage by stage. DAS interpretation was conducted during the treatment of each stage indicating the effectiveness and efficiency of the completion design. Results show that this is a very effective tool to better understand the performance of the fracturing treatment by digital transformation using DAS data. In addition, acoustic and strain measurements also validated its diagnostic capability for real-time operation monitoring. In this presentation we show how the near-field acoustic and far-field strain measurements allow for better understanding of the completion efficiency. This is by assessing the far field response to quantified DAS injected signals in the treatment. This analysis takes advantage of fiber installation on both the treatment and nearby monitor well. The fluid and proppant allocations in the near field were performed on the treatment well using relative acoustic intensities. Meanwhile, the fracture propagation induced strain change is recorded by the offset fiber well. Using this fiber data reveals dominant clusters and stage bias from near-field injection profile. Simultaneously the far-field identified fracture counts from strain further enable a geomechanical assessment of the stimulated reservoir and assess the effectiveness of the completion design. Multiple DAS fiber equipped wells not only provide single diagnostic tool for each of the fiber well, but also demonstrate significant integrated assessment of the stimulation effectiveness, completion efficiency, well interaction, and reservoir description. Availability of near and far field measurements constitutes an important tool to assess properties of the reservoir. Here we show how different vantage points can help illuminate a fracturing program in unconventional reservoirs.

Modern Drilling and Completion in Contradiction of New Artificial Lift Method Concept

In challenging times of 2020 and inconsistency with the background of a low-oil-price environment, innovative ideas needed to give a second life to all available resources such as unconventional, shallow, depleted, mature, heavy oil and by bypassed oil with a cost-effective manner (usually innovation created to fit needs). U-shaped well a combined with pigging lifting (conceptual study for new artificial lift method) is one of the selected scenarios studied under the objective of innovative, low-cost techniques to overcome many projects challenges. U shaped well accompanied with a new pigging artificial lift method are new concept studied in this lab work. Conceptual model presents many benefits of this new application such as solving most of the current wells and production challenges. The study reflects more well control with two paths, better well stimulation, low fracturing pressure and double rates, inject and lift chemical for clean without intervention, double well life "additional strings", new recompletions without rig, two horizontal side used for production or injection, step change for reservoir monitoring, improving artificial lift performance and allow creating Pigging lift "New artificial lift concept". U shaped well accompanied with a new pigging artificial lift method study shows the following progress: 1. Additional down hole barrier from the deepest point and additional open side keep the well under control more over minimize the existing well control killing procedures with low cost and risk in addition to discarding the CT operations for killing or prepare the well for W/O. 2. Decreasing stimulation pressures needs (double injection rates) and overcome the existing accessibility challenges 3. Allowing pull heading stimulation w/less displacement time and high rate and chimerical batch pumping from one side to another increase well life and eliminate PKRs risk as chimerical batches will be pigger, easier and faster. 4. Additional down hole monitoring system allowing uniform stimulation and discarding the CT operations for well stimulation and cleaning, 5. Avoiding post stimulation damage throughout fast clean-up 6. Ability to stimulate from one side with artificial lift from other side Avoiding the corrosion and erosion by faster operations 7. Allow faster plug and perf. multistage fracturing technology and overcome the unconventional well fracturing which required rate and pressure 8. Eliminate rig usage to pull the frac string to run completions 9. Step change for reservoir mentoring without S/D and real-time Logging, Sampling The deployment of U Shaped Well allows new artificial lift concept (Pigging lift) to apply. This new approach led to improved wells performance also raising efficiency of the use of the existing resources besides saving time and in return cost. This approach helps in improving well utilization and efficiency levels.

Green Well Stimulation Fluids for Enhanced Oil Recovery from Tight Sand Formations: Field Wide 70+ Wells Study Over 4 Years

Legacy oil production from Appalachian basin has been in a decline mode since 2013. With more than 80% of wells producing less than 15 bbl/day, there is a growing interest in economically and environmentally viable options for well stimulation treatments. Analysis of formation mineralogy and reservoir fluids along with history of well interventions indicated formation damage in many wells due precipitation of organics and a change in wettability being partially responsible for production decline rates in excess of forecasts. The development and properties of a novel cost-effective biosurfactant based well-stimulation fluid are described here along lessons learned from several field trials in wells completed in the Upper Devonian Bradford Group. This group of 74 wells, completed in siltstone and sandstone reservoirs were presenting more than 12 well failures annually across the field, which was attributed to the accumulation of organic deposits in the tubulars. Based on these cases, batch stimulation treatments using a novel fluid comprising biosurfactants were proposed and implemented field wide. The treatments effectively removed organic deposits, changed formation wettability from oil to water wet and resulted in a sustained oil production increase. Well failures were significantly reduced as a result of this program and the group of 74 wells did not have a paraffin-related well failure for 18 months. Results from this program demonstrates the efficiency of the green well stimulation fluids in mitigating formation damage, reducing organics deposition and in increasing oil production as a promising method to stimulate tight formations.

Influence of Abandonment Pressure on Recoverable Reserves, Special Application to the Depleted Dnipro-Donetsk Basin Reservoirs

Volumetric gas reservoirs are driven by the compressibility of gas and a formation rock, and the ultimate recovery factor is independent of the production rate but depends on the reservoir pressure. The gas saturation in the volumetric reservoir is constant, and the gas volume is reduced causing pressure drop in the reservoir. Due to this reason, it is crucial to minimize the abandonment pressure to the lowest possible level. Concerning Dnipro-Donetsk Basin (DDB) gas reservoirs, it is widespread to recover sometimes more than 90% of the OGIP. Often, OGIP was estimated not considering lower permeability gas layers due to inaccurate logging equipment used in the past, causing that such layers were not included in the total netpay. This is one of the reasons for OGIP overestimation and higher recovery factors. On many P/Z graphs, we observe that at certain drawdown, lower permeability reservoirs kick in lifting up P/Z plot curve. Abandonment pressure is a major factor in determining recovery efficiency. Permeability and skin are usually the most critical factors in determining the magnitude of the abandonment pressure. Reservoirs with low permeability will have higher abandonment pressures than reservoirs with high permeability. A specific minimum flow rate must be sustained to keep the well unloading process, and a higher permeability will permit this minimum flow rate at lower reservoir pressure. Abandonment pressure will depend on wellhead pressure, friction and hydrostatic pressures in the system, pressure drop in reservoir, and pressure drop due to skin. This last factor is often neglected, which sometimes leads to a significant reduction of the recovery factor. It is common practice that skin factor and pressure drop due to the skin are solved with well stimulation. Also, well stimulation has its limits concerning the level of reservoir pressure. It is very common that the stimulation effect of low reservoir pressure well is negligible or even negative. This is caused by the minimum required drawdown to flow back a stimulating aqueous fluid out of the reservoir. The required minimum drawdown is caused by the Phase Trapping Coefficient (PTC), which drives reservoir stimulation fluid cleaning behavior. For water drive gas reservoirs, Cole (1969) suggests that the recovery is substantially less than recovery from bounded gas reservoirs. As a rule of thumb, recovery from a water-drive reservoir will be approximately 50 to 75% of the initial gas in place. The structural location of producing wells and the degree of water coning are essential considerations in determining ultimate recovery. In the cases studied in this paper, we consider gas and rock expansion reservoir energy, if abandonment pressure needs to be coupled with a water drive, then it is recommended to use a numerical, not analytical approach.

Techno-Economic Analysis of Hydraulic Fracturing As A Solution for Developing Low-Resistivity and Low-Quality Zone on Offshore “RI” Field

Hydrocarbon production in Indonesia is continuously decreasing on a yearly basis, which is in contrast with its increasing level of consumption. Low-quality and low-resistivity reservoir zones are deemed to possess a lot of hydrocarbon potentials, however, little priority has been placed on their development due to their small level of production. The "RI" field that was utilized in this study is a mature offshore field with a reservoir which has a low-quality and low-resistivity zone. This area has been in use for more than thirty years, therefore its rate of oil production has declined. This study aims to review the techno-economic aspects of well stimulation in the form of hydraulic fracturing. And also, to determine the development method that is suitable for low-quality fields. The hydraulic fracturing process was modelled using Fracpro software as input parameters for the reservoir production simulations. The reservoir behavior was simulated using the CMG software to observe the amount of hydrocarbon liable for production in various development scenarios. Three cases were performed on the "RI" field, which was stimulated for ten years of operation. The first case was the instance with the natural flow, while the second implemented hydraulic fracturing at the beginning of production, and the third was the implementation of hydraulic fracturing, which started in the middle of the production period. Then, the three cases are evaluated utilizing a Gross Split scheme, to calculate the economics of the project both from the government and contractor's aspects. The simulation study concluded that fracturing at the beginning of the LRLC zone development is the most profitable. The novelty of this study is the comparison of scenarios for the implementation of hydraulic fracturing methods in fields with low-resistivity and low-quality zone whose economic value is evaluated by the Gross Split scheme.

A Novel Scientific Approach to Compare the Effectiveness of Well Stimulation and Artificial Lifting

Production rate decline is one of the most common challenges in production engineering. Obviously, the first step to overcome this challenge is to understand its main reason. In this article a new approach is developed which can be used to compare the effectiveness of artificial lifting and well stimulation. The method is based on a couple of charts which summarize the results of integrated simulation of formation and well-column. In the first graph, called FPI curve, production rate is drawn as a function of productivity index. Some important points are also specified on this diagram which are current state, production rate at maximum possible productivity index and production rate when the well is equipped with a pump or gas lifting. In the second graph derivative of production rate of different wells are drawn as a function of productivity index. The analysis of three actual wells with conventional IPR-TPR curves and also our suggested curves is discussed in this paper. It is seen that the introduced approach can be used as a powerful tool to predict the effectiveness of well stimulation and artificial lifting and make a clear comparison between them.

TAML-3 Multilateral Wells Construction with Multi-Stage Fracturing in Producing Wells

The article presents geological substantiations, the process and the results of the construction of a multilateral well with multistage fracturing from the existing producing well in the Yuzhno-Priobskoye field. The scope of construction of a multilateral TAML-3 well as per the international classification with a saved mainbore was to prove the effectiveness of the multilateral technology and its economic feasibility in the conditions of an extensive stock of producing wells. Every year we are seeing an increasing number of new wells being drilled in reservoirs with worsening characteristics which is caused by low permeability. Sharp production declines (up to 70% in the first year) and an increasing amount of periodic wells highlight the need to advance well stimulation methods. Well workovers by drilling a horizontal lateral while keeping the mainbore in operation allows to increase the production rate by 30% compared to a conventional sidetracking. While keeping the production rate of the mainbore, this technology provides for an additional production from a lateral bore and allows to operate the well at the planned bottomhole pressure.

Batch Production: A Success Story to Improve Oil Production in Mature Fields in Medco E&P, South Sumatera

X and Y fields are mature fields with almost 400 wells have been drilled since 1996. Many wells have been shut-in for a long time due to producing below economical limit of 10 BOPD. Several reasons are due to depleted reservoir pressure, watered out, and low reservoir quality. Long shut-in time allows the reservoir pressure to build up and improve. On the other side, good waterflood and pressure maintenance efforts also improved the reservoir pressure and oil recovery potential. Many wells become potential for reactivation. In 2018, 5 (five) wells were reactivated after a long period of shut-in. However, the initiatives were not entirely effective due to lack of established method for candidates selection and prioritization applied. Not all wells can be monitored and reviewed thus resulting in lacking of reactivation candidates. In 2019, a more comprehensive method named “Batch Production” is introduced. It is an end-to-end selection process which consists of 5 (five) lenses: well screening, reservoir aspect review, operational aspect review, prioritization, and execution and monitoring. After implementing “Batch Production” method in 2019, we successfully reactivated 35 (thirty five) wells in 2019 – 2020 with total initial gain of 1062 BOPD, which are significantly higher than 2018 result of 5 (five) wells with 184 BOPD gain. Telisa reservoir has higher initial oil gain compared to Baturaja reservoir which were mostly driven by reservoir pressure increment. This result proves how “Batch Production” method is effective and covers all the important aspects in well reactivation. It also helps the operation team by streamlining the process of reactivating a well. No additional cost such as rig intervention or well stimulation is needed in this method, making this initiative as cost-effective yet very profitable for mature fields.

A Novel Method To Assess Stimulation of Sandstone Cores Damaged by Fines Migration

Summary Sandstone stimulation remains challenging because of formation heterogeneity and the sensitivity of clay minerals to acids such as hydrochloric acid (HCl) and mud acid [HCL/hydrofluoric acid (HF)]. Fines migration complicates the well-stimulation process and reduces formation productivity. Multiple field studies show that some stimulation methods can result in permanent damage to the rock matrix near the wellbore because of fines migration. This study aims to locate, quantify, and describe the damage resulting from fines migration after the stimulation of sandstone formations, and examine the composition of clay content in the formation and its effects on the stimulation process and subsequent fines migration. This work evaluates the fines-migration damage during well stimulation in Bandera, Gray Berea, and Kentucky Sandstones. Fines migration was induced by injecting deionized water between brine stages to trigger the mobilization of the clay minerals in sample cores. HCl, formic acid (HCOOH), and HF stimulation stages were then injected after the fines-migration induction. The new formation-damage-evaluation method proposed in this work uses computed-tomography (CT) scanning and nuclear-magnetic-resonance (NMR) measurements before and after the fines-migration induction and experimental stimulation. The CT and NMR data were then combined and processed to generate a 3D representation of the pore structure throughout the core samples, which yields insight on how the clay composition affects the stimulation process and changes the pore system. The developed technique exhibited an excellent ability to visualize the pore-size distribution and the changes in the pore structure after the fines-migration damage and the acid treatment. The mapping of the pore-size distribution using CT and its comparison with the rock mineralogy of Bandera, Gray Berea, and Kentucky Sandstones successfully predicted the changes in the pore structure of these formations upon induction of fines-migration damage using deionized water. These changes in pore structure prevailed as a controlling variable of the acidizing process. The stimulation of the damaged cores at 150 and 250°F resulted in aluminosilicate deposition toward the core outlet. These deposits are attributed to the acid leaching of aluminum (Al) and iron (Fe) ions from the aluminosilicate structures. The higher temperature resulted in the deposition of aluminosilicates closer to the injection point. However, an enhancement in permeability was noticed in all of the sampled formations, which was because of the propagation of narrow channels between heavily deformed pore structures. This work adds to the understanding of sandstone-stimulation technology and contributes a new process to assess the effects of acid stimulation on fines-migration damage. The high level of resolution in visualizing the changes in the pore structure facilitates the optimization of treatments to reduce costs while improving production from clay-rich sandstone formations. This technique offers further potential as a formation-evaluation tool for real-time assessment of a variety of formation-damage mechanisms, such as fracturing fluids and water blockage.