|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
This case study describes the successful outcomes and learnings from a brownfield tie-back project in offshore Trinidad. The greater Angostura Asset consists of multiple Oligocene-age turbidite sandstone reservoirs with complex geology and compartmentalization. The Asset has produced oil since 2005 from thin oil rims overlaid by large gas caps. This has been supported by significant gas reinjection and constrained by gas coning. Commencement of gas sales added value but also increased gas cap blowdown in the oilfields. The Angostura Phase 3 project was conceptualized to enable gas production from an adjacent gas discovery and extend the overall productive life of the existing oil fields.
Key subsurface uncertainties and operational constraints were identified early in the project. Historically, drilling in the Angostura field has been challenging due to the complex geology and compartmentalization. Poor seismic data in the Phase 3 area added complexity to optimal well placement. Ensuring high deliverability was another critical project requirement. The main reservoir management challenge in the existing fields was optimizing both oil and gas sales while managing voidage and coning. Limited topside facilities and space constrained addition of new gas at flowing at higher pressures.
To address these challenges, a multi-disciplinary project team was formed to plan and execute the project. Material balance, detailed geological modeling and numerical simulation were used to understand the impact of key uncertainties on recovery. The integrated evaluation resulted in an optimized development plan with three subsea gas wells tied back to existing facilities. Production performance of existing wells helped highlight critical performance drivers for Phase 3 wells. Modified completion designs along with a flow back and stimulation program during completion helped to maximize productivity.
Phase 3 wells have performed at the high levels expected during project design and sanction. Detailed surveillance (including pressure transient analysis (PTA) and interference testing during completion, start-up and production phases) has continuously helped to optimize production. Oil production in the existing fields has also been improved by better balancing gas sales and injection. The project added significant value from the increased gas sales and oil production.
This paper discusses the planning, successful execution and impact on the overall value of the Angostura Asset from the Phase 3 project. Optimized completions along with an improved approach for evaluating stimulation options during completion (detailed near well-bore modelling, real-time PTA and simulation) enabled strong well performance. We highlight some of the critical factors for achieving success in brownfield tie-back projects including having (right from project inception): multi-disciplinary project teams, tight coordination with existing operations and a focus on key uncertainties and constraints. Building optionality and flexibility into development plans and being prepared for contingencies have been the other critical learnings from this project
The emerging Vaca Muerta Formation, located in the Neuquén Basin in Southern Argentina, is the most successful Unconventional Play outside United States. In the last few years, several blocks have initialized multi-rig development programs and operators have identified interference between existing producers and newly fractured wells during the completion. The effect known as parent-child occurs when the reservoir depletion around the parent well modifies the pore pressure and induces variations in the original stress field. As a result of this effect, the parent well could be seriously damaged, the hydraulic fracture of the child well would be less efficient and there will be an unsymmetrical recovery around the child well. The parent-child effect is usually negative and impose an additional challenge on the drilling and completion sequence of the block. This contribution is an attempt to quantify the production impact of this effect using a combination of a multi-disciplinary workflow.
Unconventional reservoirs were originally developed by small oil and gas companies with stand-alone wells spread across the different basins. Later in time when major operators started to develop these projects that requires intensive capital expenditure, the factory mode was deployed to increase operational efficiency. This development strategy requires the adjustment of well spacing and completion designs to minimize well production interference while maximizing the recovery factors and economics. Despite many optimization studies have been looking for the perfect design, the ultimate recovery of wells drilled in factory mode are negatively impacted compared to a stand-alone well. Additionally, as the development of the blocks moved forward, some new wells (child) were placed next to wells on production (parent) and operators have seen an additional negative impact commonly called parent-child. Statistical data from different US Shale Plays confirmed the negative production impact of this effect (
Pei, Yanli (The University of Texas at Austin) | Yu, Wei (The University of Texas at Austin / Sim Tech LLC) | Sepehrnoori, Kamy (The University of Texas at Austin) | Gong, Yiwen (Sim Tech LLC / The Ohio State University) | Xie, Hongbin (Sim Tech LLC) | Wu, Kan (Texas A&M University)
The extensive depletion of the development target has triggered the demand for infill drilling in the upside target of multilayer unconventional reservoirs. To optimize the hydraulic fracturing design of newly drilled wells, we need to investigate the stress changes in the upside target induced by parent-well production. In this work, an integrated parent-child workflow is presented to model the spatial-temporal stress evolution and propose the optimal development strategy for the upside target using a data set from the Permian Basin. The stress dependence of matrix permeability and fracture conductivity is determined based on available experimental data and incorporated in our reservoir simulation with the aid of an embedded discrete fracture model (EDFM). With calibrated reservoir properties from history matching of an actual well in the development target (i.e., 3rd BS Sand), we run the finite element method (FEM) based geomechanics simulator to predict the 3D spatial-temporal evolution of the local principal stresses. A displacement discontinuity method (DDM) hydraulic fracture model is then applied to simulate the multi-cluster fracture propagation in the upside target (i.e., L2BSSh) with the updated heterogeneous stress field. Numerical results indicate that stress field redistribution associated with parent-well production not only occurs within the development target but also vertically propagates to the upside target. A smaller parent-child horizontal offset induces a severer deviation of child-fractures towards the parent wellbore, resulting in more substantial well interference and less desirable oil and gas production. The parent-child fracture overlapping ratio in our study is in 0.6 ~ 0.8 for the 400 ft horizontal offset and 0.2 ~ 0.5 for the 600 ft horizontal offset. Varying the parent-child vertical offset gives the same trend as we change the horizontal offset. But with a delayed infill time, placing child-well in different layers causes more significant variation in the ultimate recovery. Moreover, infill operations at an earlier time are less affected by parent-well depletion because of the more homogeneous stress state. The candidate locations to implement infill-wells are suggested in the end for different infill timing by co-simulation of the parent-child production. With the reservoir-geomechanics-fracture model, this work provides a general workflow to optimize the child-well completion in multilayer unconventional reservoirs. The conclusions drawn from this study are of guiding significance to the subsequent development in the Permian Basin.
Thomas, F. Brent (Resopstrategies) | Qanbari, Farhad (Seven Generations Energy) | Piwowar, Michael (Stratum Reservoir) | Noroozi, Mehdi (Stratum Reservoir) | Apil, Ronnel (Stratum Reservoir) | Marin, Juan (Stratum Reservoir) | Gibb, William (Stratum Reservoir) | Clarkson, Carter (Stratum Reservoir) | Zhang, Hongmei (Stratum Reservoir) | Swacha, Stan (Stratum Reservoir)
An experimental apparatus was developed that provides axial fracture flow and radial matrix flow in the context of differential pressure gradients at full reservoir conditions. Flow within the frac(s) and flow between frac(s) and matrix are operative in the system. The influence of cycling pressure, injection gas composition, soak time and level of primary depletion before initiation of GCEOR have been measured previously with volatile oil systems. To date no direct comparison has been made with rich gas condensate GCEOR performance in the same rock with similar GCEOR design parameters. Primary depletion of a volatile oil in a Montney porous media is compared to primary depletion in the same rock with a rich gas condensate. Pursuant to primary depletion, GCEOR was applied for both the oil and the gas condensate fluid.
A novel experimental design for core-flow testing has permitted the quantification of GCEOR using large lab-scale hydro-carbon pore volumes (HCPV). The unique experimental design allows nano-Darcy media to be tested using a time line comparable to conventional millidarcy media. The porous media tested herein exhibited a reservoir oil permeability of 110 nD at full reservoir conditions. Mechanisms for EOR have been described previously on the basis of this experimental protocol. Due to the large hydrocarbon pore volume of this procedure (130 to 480 ml) measurements of produced gas, liquid and recombined fluid compositions are obtained, as a function of Puff cycle number, as well as produced liquid densities and recovery factors cycle to cycle. These procedures were applied to a volatile oil and a retrograde condensate fluid.
A naturally-fractured porous media was saturated with a dew point fluid exhibiting a condensate-gas ratio of 200 BBL/MMscf. Primary depletion was conducted following a linear pressure depletion corresponding to field-real primary production times scaled to the laboratory experiment. Liquid recovery factor, produced fluid compositions and densities along with frac and matrix pressures were recorded. Pursuant to primary depletion GCEOR was conducted in order to quantify the increased liquid recovery after primary production. The system was then extracted to determine Sor. The porous media was then re-saturated and restored with volatile oil and primary depletion followed by GCEOR. It was observed that liquid recovery factor was better for the gas condensate in this low-permeability porous media. Primary depletion produced higher liquid recovery (C6+) with the gas condensate fluid than with the volatile oil. GCEOR after primary depletion performed similarly. Other insights were obtained and are discussed.
This paper describes a novel process that uses standard drilling data obtained during the drilling of an infill well to identify induced hydraulic fractures that were created during the stimulation of a legacy well. Five case studies are presented to illustrate some insights gained through the application of this process.
This method of detecting fractures involves analyzing the amount of energy expended during the drilling of an infill well. Localized depletion around induced fractures created during stimulation of a legacy well and subsequent production can result in an increased differential pressure between the wellbore and the formation while drilling. This increased differential results in more energy being required to drill through the localized depletion caused by the fracture, allowing these fractures to be precisely located. Mapping these fractures allows operators to gain significant insight in to fracture growth and depletion patterns. In addition, by avoiding these areas of localized depletion during completion, negative fracture interactions can potentially be significantly mitigated or even avoided.
The 5 case studies presented show how this technique has been utilized to understand drainage patterns in stacked plays and how it can be used to understand the extent of dominant fractures being created as well as the horizontal stress orientation as indicated by the fracture direction. The method being deployed in this paper was developed, in February of 2019. This paper is the first to describe how this technique has been used in multiple applications, across multiple basins and reservoirs, to gain insight in to fracture growth and reservoir development as well as to mitigate fracture interactions which have been plaguing the industry.
As more unconventional resource development programs move to an infill drilling phase, understanding the interactions between primary/legacy (parent) and infill (child) wells is becoming more and more important. In some cases, these interactions are positive with no long-term damage to the parent well and can sometimes even increase the production. In many cases though, these "frac-hits" can be quite damaging to the parent wells with loss of production, increased water cut, sand fill, casing collapse or loss of the parent well. Loss of treatment fluid and proppant to the parent well can also mean that the child well is less effectively stimulated resulting in a reduction of potential production from the child well and lower ROI on the infill drilling program. It is because of these risks that many operators seek to minimize primary & infill well interactions.
Production underperformance of a historical infill (child) lateral well was confirmed by observation and modeling to be due to offset vertical well interference. These results led to utilizing a seismic-driven earth model, three-dimensional hydraulic fracture, and reservoir models for a planned horizontal well. The goal was to apply past learnings to maximize completion potential and understand the economic viability of infill horizontal well development in the Greater Green River Basin. The results of this study provided insight to determine future horizontal development strategy.
In-situ model input parameters along with field-scale structure were informed by 3D seismic and vertical log data. Parameters were further calibrated to core and offset well DFIT’s with subsequent treatment history matching validation. Modeled fracture geometries were incorporated into a reservoir simulator to history match parent well production. This exercise provided an accurate representation of pressure depletion and stress profiles around the planned horizontal child well. Additionally, this provided a platform to investigate potential completion strategies, landing zones, and a subsequent production assessment based on uncertainty analysis to determine economic potential.
Targeting a deeper landing location compared to the previously drilled horizontal well resulted in reduced expected interaction with offset wells. Hydraulic fracture design sensitivities indicated child well frac hits and asymmetrical fracture growth can be mitigated or lessened with increased intra-stage cluster count and efficiency to prevent "super frac" generation.
An assessment based on fracture model sensitivity results were coupled with reservoir uncertainties to forecast production. Simulation indicated that the most significant impact on production was a result of porosity, saturation, and permeability assumptions. Two separate models were developed, one based on log derived properties and the other being inferred from core properties and assigned to facies from Gamma Ray. The objective of the stimulation was to maximize hydraulic fracture flowing area with fluvial sand bodies while minimizing cost. Increased sand loading was thought to be the primary driver. The simulation showed that increasing sand loading from 1000 lb/ft to 1500 lb/ft only generated an incremental 0.2 Bcf indicating the lower amount of sand is the economical choice. Capital savings were generated by increasing the stage length while maintaining cluster efficiency reducing stage count by 5. However, even with the capital savings, forecasted production scenarios averaged around 7.15 Bcf missing their economic breakeven. As a result of this work, the decision was made not to drill the well and instead explore alternative prospects for horizontal development.
We conducted a comprehensive analysis of approximately 7000 horizontal wells drilled in the Middle Bakken formation between 2007 and 2016 to assess the impact of well orientation on cumulative production. While it is common practice to drill horizontal wells "on-azimuth", that is, in the direction of the minimum horizontal stress (Shmin), there is a diversity of well orientations in the Bakken. Shmin is consistently oriented N42°W throughout the production area. Our analysis clearly demonstrates that wells drilled in the direction of Shmin ("on-azimuth") produce more barrels per foot than wells in other directions, both in the core area and across the entire Bakken play. However, the amount of uplift gained from drilling on-azimuth wells decreases as the field matures, which we hypothesize is due to depletion. We found that the relationship between production and well orientation is consistently observed, regardless of the amount of proppant used. An economic analysis indicated that for wells of equal length, it is clearly beneficial to drill wells in the direction of Shmin. However, wells in the direction of Shmin are consistently shorter in length than off-azimuth wells, and it is generally more efficient to drill longer laterals on a given leasehold. Nevertheless, using the average oil price at the time the wells we studied were drilled, we find that the shorter wells in the on-azimuth direction have a significant economic uplift of several million dollars per well relative to the longer wells drilled in the off-azimuth direction.
Hydraulic fractures propagate in a plane perpendicular to the least principal stress (Hubbert and Willis, 1957) which normally means that hydraulic fractures propagate in vertical planes, normal to Shmin in areas characterized by strike-slip or normal faulting. When exploiting unconventional oil and gas reservoirs, it is common to drill horizontal wells with multiple hydraulic fracturing stages in the direction of Shmin. If the spacing between adjacent wells reflects the drainage area associated with the propped half-lengths of the hydraulic fractures of the wells, it would seem to result in optimal recovery. This said, in some areas wells are drilled in north-south or east-west directions regardless of the stress orientation to 1) optimally exploit available acreage with the highest number of wells and 2) take advantage of the fact that drilling longer wells decreases drilling and completion costs on a per foot basis.
In this paper we study the relationship between well orientation (relative to the stress field) in the Bakken play to assess its effect on production. The Bakken shale play is in the Williston Basin straddling a region of 200,000 square miles across western North Dakota, eastern Montana, Saskatchewan, and Manitoba. Unconventional oil production started in 2006 and peak oil production reached its maximum to date in 2019 with approximately 1.5 million barrels per day (EIA, 2020a). We have restricted this study to wells drilled in the Middle Bakken formation to avoid intermingling data from the less productive Three Forks.
Pore pressure depletion, in response to production, impacts the economics of child wells by reducing contact with virgin reservoir. In some cases, depletion increases the likelihood of sustaining damaging frac hits in the parent well by creating a pressure sink that directs fracture growth towards the parent. Identification of depleted zones in child wells allows an operator to mitigate these negative effects during stimulation and gain insight into optimal well spacing in four dimensions.
Several methods for pore pressure calculation and depletion identification were evaluated in the Eagle Ford Formation, in southeast Texas. Methods included geomechanics-based estimates using a modified Eaton’s equation and using drill bit vibration data, and from a drilling-efficiency method using surface and down-hole data. Mud gas mass spectrometry data were analyzed for depletion indicators and used to create an independent depletion flag. The results of these analyses were evaluated for simplicity and reproducibility. The geomechanical and mud gas-based methods were combined and compared to completion data, offset pressure gauges in the parent wells, and production responses.
Of the geomechanics-based models evaluated, the model that shows the most promise uses the modified Eaton’s equation with Young’s Modulus from drill-bit vibrations and a variable baseline trend using MWD gamma ray. The advantages of this method include the simplicity of modeling the baseline (relative to Young’s Modulus) and optimal signal-to-noise ratio relative to a similar model using only surface data. Using a variable trend reduced the subjectivity of selecting the property’s baseline. Results indicate that the values of pore pressure calculated with this method were extremely sensitive to small changes in the fitting factor, such that without calibration to accurate pore pressure measurements, the results are only relative and give directional responses.
Correlations between the depletion estimates from geomechanical data and indicators of depletion in the mass spectrometry analysis were generally strong, which increases confidence in the final combined interpretation. Additionally, these results were compared to one-second treatment data on a stage-by-stage basis.
Several models were evaluated for characterizing depletion in horizontal wells and a workflow was developed that is simple and reproducible. The multi-variate approach results in a stage-by-stage risk assessment based on mutually reinforcing data sets. By identifying depletion prior to stimulation, this analysis allows the operator to mitigate risk and improve both parent and child well economics.
This study uses a machine learning framework to systematically analyze field production and completion data to understand the impact of frac-hits on parent and child wells and predict well spacing and completions design. Frac hits are one of the most pressing reservoir management issue that can enhance or compromise production over either the short-term or have sustained impacts over longer times. The extent of the impact is dictated by a complex interplay of petrophysical properties (high-perm streaks, mineralogy, etc.), geomechanical properties (near-field and far-field stresses, brittleness, etc.), completion parameters (stage length, cluster spacing, pumping rate, fluid and proppant amount, etc.) and development decisions (well spacing, well scheduling, etc.). As a result, the impact of frac-hits is not straightforward and difficult to predict.
The study uses data from the Meramec, Woodford and Wolfcamp formations. We develop an automated machine-learning based frac-hit detection algorithm that also quantifies the impact on the parent and child wells using matched decline curve models. We analyze about 500 parent and over 1100 child wells in the three formations. Our results show that the key factors governing the extent of the impact are the extent of depletion and producing oil rate of the parent well before frac hit, completion design parameters (fluid and proppant amount) and well spacing. Our machine learning analysis generates regression models to predict the impact of frac hits. These regression models are coupled with economic analysis to determine optimum spacing for any given completion design or optimum completion design for any given spacing.
The parent wells in all three formations had both positive and negative impact of the frac hits. Around 60–67% parent wells were negatively impacted while 33–40% wells were positively impacted. For the child wells, 71–85% wells were negatively impacted and 15–29% of the wells were positively impacted. Combining the impact on parent and child wells, the impact is dominated by the child wells as 69 to 82% of the parent-child pairs were negatively impacted and only 18–31% of the pairs were positively impacted. Considering percent loss in cumulative oil volumes in the next 5-years, in the Meramec, parent wells on average show a 16% reduction while child wells show a 39% reduction due to frac hits. The corresponding numbers for the Woodford formation are 19% and 37% and Wolfcamp formation are 20% and 22%, respectively. This translates to a parent well losing on average 40–50 thousand bbls in next five years and a child well losing on average 130–150 thousand bbls in the same period.
This study systematically analyzes available data to understand the impact of frac hits and formulates a machine learning-based well spacing-well completions matrix workflow that can easily be extended to other formations by integrating commonly available production and completions data.