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Abstract Characterization of hydraulic fracture system in multi-fractured horizontal wells (MFHW) is one of the key steps in well spacing optimization of tight and shale reservoirs. Different methods have been proposed in the industry including core-through, micro-seismic, off-set pressure data monitoring during hydraulic fracturing, pressure depletion mapping, rate-transient analysis, pressure-transient analysis, and pressure interference test. Pressure interference test for a production and monitoring well pair includes flowing the production well at a stable rate while keeping the monitoring well shut-in and recording its pressure. In this study, the coupled flow of gas in hydraulic fractures and matrix systems during pressure interference test is modeled using an analytical method. The model is based on Laplace transform combined with pseudo-pressure and pseudo-time. The model is validated against numerical simulation to make sure the inter-well communication test is reasonably represented. Two key parameters were introduced and calculated with time using the analytical model including pressure drawdown ratio and pressure decline ratio. The model is applied to two field cases from Montney formation. In this case, two wells in the gas condensate region of Montney were selected for a pressure interference test. The monitoring well was equipped with downhole gauges. As the producing well was opened for production, the bottom-hole pressure of the monitoring well started declining at much lower rate than the production well. The pressure decline rate in the monitoring well eventually approached that of the producing well after days of production. This whole process was modeled using the analytical model of this study by adjusting the conductivity of the communicating fractures between the well pairs. This study provides a practical analytical tool for quantitative analysis of the interference test in MFHWs. This model can be integrated with other tools for improved characterization of hydraulic fracture systems in tight and shale reservoirs.
Ji, Qin (Reveal Energy Services) | Vernon, Geoff (Earthstone Energy) | Mata, Juan (Earthstone Energy) | Klier, Shannon (Earthstone Energy) | Perry, Matthew (Reveal Energy Services) | Garcia, Allie (Reveal Energy Services) | Coenen, Erica (Reveal Energy Services)
Abstract This paper demonstrates how to use pressure data from offset wells to assess fracture growth and evolution through each stage by quantifying the impacts of nearby parent well depletion, completion design, and formation. Production data is analyzed to understand the correlation between fracture geometries, well interactions, and well performance. The dataset in this project includes three child wells and one parent well, landed within two targets of the Wolfcamp B reservoir in the Midland Basin. The following workflow helped the operator understand the completion design effectiveness and its impact to production:Parent well pressure analysis during completion Isolated stage offset pressure analysis during completion One-month initial production analysis followed by one month shut-in Pressure interference test: sequentially bringing wells back online Production data comparison before and after shut-in period An integrated analysis of surface pressure data acquired from parent and offset child wells during completions provides an understanding of how hydraulic dimensions of each fracture stage are affected by fluid volume, proppant amount, frac stage order of operations, and nearby parent well depletion. Production data from all wells was analyzed to determine the impact of depletion on child well performance and to investigate the effects of varying completion designs. A pressure interference test based on Chow Pressure Group was also performed to further examine the connectivity between wells, both inter- and intra-zone. Surface pressure data recorded from isolated stages in the offset child wells during completions was used to resolve geometries and growth rates of the stimulated fractures. Asymmetric fracture growth, which preferentially propagates toward the depleted rock volume around the parent well, was identified at the heel of the child well closest to the parent. Fracture geometries of various child well stage groups were analyzed to determine the effectiveness of different completion designs and the impact of in situ formation properties. Analysis of parent well surface pressure data indicates that changing the completion design effectively reduced the magnitude of Fracture Driven Interactions (FDIs) between child and parent wells. Child well production was negatively impacted in the wells where the fracture boundary overlapped with the parent well depleted volume in the same formation zone. This study combines pressure and production analyses to better understand inter- and intra-zone interference between wells. The demonstrated workflow offers a very cost-effective approach to studying well interference. Observing and understanding the factors that drive fracture growth behavior enables better decision-making during completion design planning, mitigation of parent-child communication, and enhancement of offset well production.
Abstract The detection and quantification of horizontal-permeability anisotropy play a vital role in optimally placing geothermal wells in geothermal reservoirs and thereby maximizing the geothermal-energy recovery from a given geothermal-reservoir area. However, the study of permeability anisotropy within the horizontal plane has received less attention and often permeability anisotropy is neglected in view of simplification. Our study show that the horizontal permeability anisotropy has been observed in nearly all geothermal doublets that have been tested so far in the Netherlands. The main objective of this work is to study the impacts of horizontal permeability anisotropy inferred from pressure-interference tests on geothermal-doublets performance. A theoretical relation between the measured directional permeability and the elements of the permeability tensor are presented. In a case study, horizontal anisotropy has been detected and quantified using a pressure-transient analysis, interference test, and the knowledge of the reservoir geometry gained from the geological study. In addition, this work uses a detailed three-dimensional thermal reservoir simulator of a reservoir in the West Netherlands Basin to demonstrate the importance of considering permeability anisotropy in predicting the lifecycle, which is determined by the cold-temperature breakthrough of an existing doublet and in optimally designing the second doublet in the same licensed area. It has been established that the areal permeability anisotropy plays an important role in the energy sweep efficiency and doublets placement. A correct arrangement between the permeability anisotropy direction and the placement of the wells leads to longer breakthrough time and increasing the heat sweep efficiency. This work shows that the knowledge gained from the interference test and/or other experiments about the presence, direction, and scale of anisotropy can be used to adjust the reservoir model that can be further used to design and optimize geothermal doublets.
Abstract Reservoir characterization is a key aspect during the appraisal and production phases of a field development. Understanding the reservoir property distribution and dynamic behavior reduces uncertainties and helps to improve recovery while optimizing investments. Modern seismic and logging tools, combined with core data, provide multi-disciplinary teams with better data quality. However, the reservoir heterogeneity and connectivity, often remain uncertain until several years of production have been achieved. This is true of naturally fractured reservoirs, for which fracture connectivity can only be characterized dynamically. In order to provide earlier dynamic connectivity information in a field development, interference tests have been developed to define whether parts of a reservoir are in communication, and to estimate reservoir properties between wells which is not possible from log measurements and correlations. Interference tests are ideally conducted when a reservoir is in equilibrium with homogeneous and fully stabilized pressure through the entire field. This paper describes a new methodology for interference test interpretation when reservoir pressure is not stabilized, and also describes how to optimize multi-well interference operation sequencing. First, the observation well is tested, and second, active wells are produced in a sequence while the observation well bottom hole pressure (BHP) is still building up. Pressure changes only related to the interference are extracted from the pressure measurements at the observation well by removal of the build-up effects. Interpretation is subsequently performed to quantify reservoir properties such as matrix and fracture permeability and porosity to match interference time lag (also named time of flight), pressure and depletion amplitude. Permeability anisotropy and fracture connectivity are defined and quantified at the field scale. The application of this new methodology to multi-well interference tests performed on a naturally fractured gas reservoir is presented in this paper. Using this methodology can prove connectivity through open natural fractures and quantify the fracture network properties even when there is a very small interference amplitude. Defining the extent of a natural fracture network and its contribution to the hydrocarbon production is crucial for naturally fractured reservoir development and reservoir management. In addition the described methodology was applied to calculate gas volumes dynamically connected to the wells. The capability to interpret an interference test performed while the pressure measured at the observation well is still building up allows a significant operational time and cost reduction while ensuring accurate interpretation of reservoir parameters. This methodology can be applied to an interference test including a well pair or multiple wells.
Mishrif formation has complex combination of stratigraphic and structure traps in western part of Onshore Abu Dhabi where according on petroleum system in western onshore Abu Dhabi there are three formations play roles; Shilaif formation acts as source rock, Mishrif as reservoir and Tuwayil seal as seal. Historically during the past decades less commercial discoveries have been thriven in Mishrif formation.
Generally, Mishrif formation consists of three Units: a lower Unit composed of fine-grained bioclastic packstones and wackestones, which represent distal shelf slope environment. The middle unit consists of medium-grained packstones indicative of proximal shelf slope environment. The upper Unit consists of coarse-grained bioclastic and shelly packstones and grainstones (rudist shell and debris) indicative of shoal of environment. Mishrif shoals are the favorable area where hydrocarbon charging was controlled by the heterogeneity inside shoal which has good reservoir qualities in term of porosity, permeability and oil saturation.
This case study is unique where the marginal field has several Mishrif reservoir pockets due to combination traps; stratigraphic and structural traps where lateral facies heterogeneity also plays a crucial part.
Several wells have been drilled and tested in Mishrif Formation during 1970's however the result still not encouraging and the company recently drilled appraisal wells; two vertical and one long horizontal well has been drilled towards an existing well and interference well test been implemented. Comprehensive data integrations of G&G and Reservoir Engineering are incorporated to generate/build new subsurface understanding with numerous geological concepts and several analog fields have been considered in order to generate new understanding.
Abstract The main objectives of field development are to maintain high profitability, as well as to achieve the highest coefficient of oil recovery (COR). One of the ways to ensure a high COR for oil fields is creation of a reservoir pressure decrease system (RPD). So, for example, when create a system of RPD, the COR can reach 0.5 d. q., and without RPD - only 0.1-0.2 d. q In the case of designing the development of oil fields with a complex geological structure (the presence of a gas cap, block structure of the Deposit, a large number of faults), the complexity of the task of choosing the optimal development system increases significantly. In Russia and in the world, there are a considerable number of oil fields that have been developed for a long time on the depletion mode, which has led to the formation of a considerable volume of the free gas phase. Such deposits often pass into the category of problematic and are characterized by low current values of the coefficient of oil recovery (COR), as well as the lack of reliable technological solutions for their effective development. Examples include the Talinsky area of the Krasnoleninsky field, the oil pool in the Jurassic sediments of the Novogodnee Deposit, and others. When the pressure increases further, for example, by pumping water, modeling the development of such deposits requires the use of non-equilibrium hydrodynamic models. Application of the results of the pressure interference test (PIT) allows us to obtain valuable information about the connectivity of inter-well intervals, a quantitative assessment of the conductivity of reservoir faults, and, consequently, reduce risks when planning field development, increase the efficiency of ongoing geological and technical measures and their profitability. Conducting of PIT on a working stock, in comparison with classical methods, allows you to minimize the loss of production during research. Proper planning of field development with the involvement of PIT results, in particular-the introduction of the RPD system, allows to increase the COR and profitability of the development system as a whole. The paper shows the results of the pressure interference test studies for a tectonically complicated structure of an oil and gas condensate field. Based on the results of the research, the efficiency of the existing RPD system was evaluated and decisions were made to transfer production wells to injection, taking into account the assessment of the risks of water breaks through conducting faults. In addition, the results of the pressure interference test were combined with the results of tracer studies. The convergence of research results by both methods is shown.
Dair, Yerkinbek (North Caspian Operating Company) | Li, Dachang (North Caspian Operating Company) | Saifutdinov, Raif (North Caspian Operating Company) | Yergaliyeva, Bakyt (North Caspian Operating Company) | Karabakiyeva, Gulsina (North Caspian Operating Company) | Ehighebolo, Ivbade Thaddeus (North Caspian Operating Company)
In order to run reservoir simulation efficiently, a coarse scale (CS) dynamic model is created by upscaling of a fine scale (FS) static model. All history match (HM) changes usually done in the CS dynamic model need to be downscaled to FS for geological justifications and consistency maintenance between the FS static and CS dynamic models. This paper proposes a robust downscaling method for integration of FS static and CS dynamic models. The proposed method downscales a HMDM (dynamic model) to HMSM (static) in multiple steps. Scale-up the ISM (initial) to CS to create an IDM. Identify the cell changes between HMDM and IDM, and transfer the changes to FS to create a MSM (modified). Scale-up the MSM to CS to create to a MDM and calculate the ratios between HMDM and MDM for all cell properties. Transfer the ratios to FS to create a HMSM. Scale-up the HMSM to CS to confirm its identity to the HMDM. Selection of sampling and zone mapping methods is critical in all steps. The proposed method has been successfully applied in a giant carbonate oil field in the Caspian Sea that consists of a matrix dominated platform and a fracture/karst dominated rim. Due to the field's complex geology and high H2S content (15%), a dual porosity, dual permeability compositional model has been created to model compositional sour crude flow within/between matrix and fracture/karst. The FS static model contains a 236m × 236m horizontal grid with 593 layers while the CS dynamic model has the horizontal cell sizes in a range of 236m to 944m with 73 layers. Rock regions, permeability, and reservoir connectivity in the CS dynamic model were calibrated using the field historical production data (e.g., static pressure, PLT, interference test, and GOR/water-cut data) to create a HMDM. Since the HM process was performed only in the CS dynamic model, the FS static model and HMDM became inconsistent. Appling the proposed downscaling method has helped the HM team to resolve this issue and resulted in a seamless link between the FS static and CS dynamic models for current and future HM and model updates.
PKKR JSC operates a couple of dozens of fields with more than a thousand wells. Consequently, a massive wells' surveillance program is conducted which includes pressure transient testing (PTT) and analysis (PTA). It leads to different kinds of cases which, eventually, help us to understand challenging issues. Thus, in the paper we try to shed light on how these data are critical to make the right decision with the aim of getting economical benefits for the company.
Field operation performs PTT on 70-80 wells annually such as pressure buildup and deliverability on producers, pressure falloff on injectors and interference tests on observation wells. All the tests are interpreted by the engineers of the company refusing from service companies during oil price decline in 2015 and purchasing commercial software. Using the software interpreter builds Horner and log-log plots, IPR curve which give the quantitative and qualitative parameters of near the wellbore, undamaged zones and outer boundary conditions. This information coupled with geological and production data are analyzed to gather puzzles into one full picture.
As the result of PTA the company could make important decisions which brought to millions of dollars of savings and earnings. The paper demonstrates standard cases, e.g. a pressure buildup test on a well helped to decide to execute fracturing and multiple time increase in oil rate was obtained. Oppositely, on another well falloff test showed presence of fractures, hereby, planned stimulation measures were cancelled in spite of low injectivity. In addition, falloff tests give additional information on how waterflooding is effectively carried out. Another case which was under active discussion includes the issue of converting a well to water injection, so we conducted an interference test and it reveals no response on adjacent producers. Again the company avoided the wrong decision and waste of money. Moreover, interference tests played a vital role in an extraordinary case where it was unclear how the wells produced gas more than reserves. Unexpectedly, the reason was a communication between two lithologically different reservoirs via fractures. So, it dramatically changed the geological concept of the field. There are other situations when PTA results help to characterize geometry of the reservoirs, presence of faults, their transmissibility, fractures distribution which all are critical for static modeling and dynamic simulation.
PTA is a crucial part of geology and petroleum engineering. It essentially helps engineers and managers to make right decisions. Sometimes it leads to big savings or significant profit earnings due to conducting or avoiding the works. Also PTA can change the geological picture of the whole field if properly analyzed. Thus, it is a powerful tool in the hands of geologists, reservoir and production engineers.
Abstract Well spacing and completion optimization in tight and shale reservoirs is a multi-dimensional task which comprise reservoir rock and fluid characterization, well performance study, inter-well communication analysis, and economic evaluation. Two sources of pressure data for characterization of inter-well communication include offset well pressure monitoring during hydraulic fracturing and controlled communication (interference) tests through staggered production. Both types of inter-well communication tests have become common among the operators in tight and shale reservoirs. However, quantitative analysis tools for interpretation of the test results are in their infancy. The focus of this study is quantitative analysis of pressure interference tests. In this study, an analytical model is developed for quantitative analysis of communication between multi-fractured horizontal wells (MFHWs) using pressure data from production and monitoring well pairs. The governing partial differential equation for the more general case of coupled flow in hydraulic fracture and matrix systems is solved using the Laplace transform. In order to validate the analytical model, the results from the analytical solution are compared against numerical simulation models. The analytical model of this study is applied to two field case from Montney formation. In these cases, a well from a multi-well pad is put on production and bottom-hole pressure of a monitoring well from the same pad is recorded using down-hole recorders. Communications between the wells is quantified using the analytical models of this study. The model of this study serves as a novel and practical tool for quantitative analysis and interpretation of inter-well communication in MFHWs. Integration of the model with other direct diagnostic and measurement tools can provide insight into optimized completion intensity for MFHWs.
Infill development typically strives to improve resource recovery while maximizing economic objectives of the organization. Success is dependent on many variables, several of which include well spacing, completion design, and mechanical stratigraphy. Optimizing development is contingent upon understanding how these variables interact with one another and what combination of development strategies will maximize the company objective. One of the challenges with optimizing horizontal multi-frac wells has been quantifying well to well connectivity, understanding the appropriate amount, and how various development strategies impact that relationship. This paper will present a case for development optimization by integrating the results of multiple quantitative pressure interference tests with completion design and well spacing in the STACK play. The framework for quantifying the connectivity between wells was developed by Chu et al (2018) and is often referred to as Chow Pressure Group (CPG). Using this technique, the Magnitude of Pressure Interference (MPI) was quantified between 25 horizontal wells within 10 development units. The dataset is unique because the infill units were developed with varying completions and well spacings which provides an opportunity to isolate and understand how each variable directly impacts well to well connectivity. This study also addresses the desired amount of connectivity between horizontal wells and how it impacts well performance and recovery.
The results from this case study suggest there is a clear relationship between well spacing and MPI, consistent with the findings by Chu et al (2018). Ultimate recovery was investigated and found to have a correlation with the amount of connectivity between development wells. Additionally, at consistent well spacing, higher proppant volume per cluster increased MPI and Estimated Ultimate Recovery (EUR) per well. Increasing proppant per cluster is likely extending the conductive half-length, increasing fracture overlap and MPI, and reducing bypassed resource beyond the tips of the fractures, resulting in higher EUR and Drilling Spacing Unit (DSU) recovery.
This case study provides asset teams with valuable relationships between reservoir, completions, geologic characteristics and how they tie to well performance in the Anadarko Basin. These relationships are expected to be different in every basin/formation, however, it highlights the power of quantitative interference tests in optimizing infill development and understanding the appropriate amount of well to well connectivity. This work also lays out a practical example regarding the dependent nature of completions and reservoir well spacing which can serve as a workflow for asset teams working unconventional plays across the world.