|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
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 (
Gonzalez, Daniel (Chesapeake Energy) | Holman, Robert (Chesapeake Energy) | Richard, Rex (Chesapeake Energy) | Xue, Han (Schlumberger) | Morales, Adrian (Schlumberger) | Kwok, Chun Ka (Schlumberger) | Judd, Tobias (Schlumberger)
Abstract The stress state at infill wells changes as a function of production from the existing producer. Understanding spatial and temporal in situ stress changes surrounding drilled uncompleted (DUC) wells or infill wells has become increasingly important as the industry works through its inventory of DUC wells and redesigns infill wells with an engineering approach. Optimizing infill/DUC well completion designs requires an estimation of the altered in situ stress state. This study presents the concept of a "production shadow" as the stress change in four-dimensional space, affecting well performance and optimal well configurations for pad development. The production shadow accounts for the compound effects from both hydraulic fracture mechanical opening and stress-state alteration from depletion. This paper details an Eagle Ford case study integrating production shadow effects into the parent and infill well hydraulic fracture modeling as well as "frac hit" analysis. The production shadow influences the degree of fracture complexity developed by the infill/DUC well stimulation. Understanding and accounting for the production shadow are critical in engineering to establish and preserve an optimal connection of the induced stimulated fracture network to the wellbore.
Since late 2017, the Haynesville Shale has seen an uptick in activity as more operators have started to drill more new shale wells than at any other time since the industry was slowed due to declining oil price at the end of 2014. Some of the new activity has been focused on pushing the economic boundaries of the Haynesville shale out whereas others have focused on drilling infill wells or wells that are drilled between pre-existing wells (known as "parent wells"). Parent wells may cause pressure depletion in the reservoir, potentially hindering the performance of new infill wells. The distance from the parent well to an infill well along with the degree of reservoir depletion caused by the parent well impact, to varying degrees, the production results of the infill wells. It is important to design a completion program in the infill well that minimizes the potential negative impact of depletion. This paper presents detailed studies assessing the impact of the change in offset well spacing and reservoir depletion related to parent wells on infill well performance through modeling in the Haynesville shale. An actual reservoir dataset was utilized in the Haynesville shale to build the parent well hydraulic fracture and reservoir simulation models to account for fracture calibration and production history matching. The models' results were then used to evaluate the impact of production depletion on the stress reorientation and changes in stress magnitude through a coupled boundary element and finite element model residing in a geomechanics simulator. Three different production depletion times were modeled through the simulation, 0.5, 1, and 3 years, to understand the timing impact on the infill well production. After the stress in the model was updated for each case, a child well pad was added to the model adjacent to the parent well. The well spacing, stimulation job treatment, and fracture stimulation pump rates were all varied for child well simulation and evaluated to understand their impacts on the created complex fracture propagation and total system hydrocarbon recovery. In this study, more than 200 different scenarios were simulated by using cloud computation, and each parameter was compared for varying spacing scenarios for the three depletion time horizons. This study can help the understanding of well spacing, completion job design, and reservoir depletion impact on the new infill well performance and help the optimization of the infill well completion strategy to achieve optimum production performance for new infill wells and minimize communication or fracture hits to the existing parent wells in the Haynesville.
Analysis of Devonian shale production histories without careful data screening can easily mislead even the most exacting investigator. Trends established from cumulative production data may not accurately represent the true production pattern. The difference between a good well and a poorer producer may be the result of fracture depletion or the length of actual producing time (among other factors) rather than a change in reservoir quality. The use of matrix controlled production information, derived from decline curves, appears to resolve this problem.
Columbia Gas is performing a study aimed at identifying the mechanisms controlling Devonian shale productivity. To accomplish this Columbia is productivity. To accomplish this Columbia is evaluating relationships among geological setting, reservoir parameters, production data and man-made influences (e.g. stimulation). Approaches to the study consist of a production pattern analysis and an individual well study. The former concerns a large scale regional examination of production data. Hopefully, a correlation will exist between production trends and mappable tectonic and/or depositional production trends and mappable tectonic and/or depositional features. The individual well study/deals with the identification of specific permeable features controlling productivity in a given well.
This paper presents preliminary information regarding Devonian shale production data as it applies to this study. Specifically, this paper will: (1) look at criteria for classifying wells as Devonian shale producers; (2) identify factors which directly influence productivity; (3) show how different interpretations can result from the use of various types of production data; and (4) suggest a method for selecting production data used in establishing production patterns.
The concept developed in this paper should result in reliable identification of producing trends. This idea evolved very early in the study. Future refinement of this approach and its application are anticipated as this Gas Research Institute sponsored project continues. project continues. IDENTIFICATION OF SHALE WELLS
The first step in evaluating shale data involves determining whether the wells in fact produce from the shale. Many "shale" wells contain other horizons which contribute to production. The unwitting inclusion of that data will result in a production bias. That is, a "shale" well, good or poor, would mistakenly appear better because of nonshale production. The use of such information may introduce production. The use of such information may introduce significant errors into the identification of apparent production trends; it could also adversely affect the individual well study selections and subsequent analyses. To minimize potential problems, it becomes necessary to identify a well as exclusively producing from the shale or to qualify it as a shale producer.
Classification of a well as a shale producer results if the method of completion exposes only the shale horizon to the wellbore. Figure 1 depicts several examples of shale producers. The wellbore on the left shows all horizons cased off and isolated from each other by cement; shale production enters the wellbore through perforations. The middle sketch depicts an open hole shale completion. Cemented casing partially penetrating the shale isolates other horizons from the shale. The right diagram shows another zone explosed to the wellbore. However, a packer isolates the shale production from the nonshale interval. In the situations described, the assumptions include: no communication between the shale and other formations via natural or induced fractures; no channeling behind casing due to poor cement bond; or no casing, tubing, and packer leaks.
The wellbore configurations in Figure 1 represent a few desired geometries for shale well classification. However, many shale wells contain other potentially productive formations exposed to the potentially productive formations exposed to the wellbore (Figure 2).
Abstract The Barnett Shale is one of the first unconventional shale plays developed with multistaged, fracture-stimulated horizontal wells in the world. It is located in North Central Texas near Fort Worth. At the end of 2013, the Barnett Shale had over 14,000 multistaged hydraulically fractured horizontal wells (MFHW) with approximately 7,600 of these wells with over five years of production history. In addition to these MFHW, there are approximately 4,000 vertical wells. Production forecasting for unconventional reservoirs with MFHW is a topic with a great amount of interest. The question is what are the appropriate decline parameters to be used in the forecast? Are multisegment forecasts with their own decline parameters necessary? Currently, production forecasting using a modified hyperbolic Arps equation is still widely accepted. This work provides analysis in characterizing decline parameters during and after linear flow for horizontal wells in the Barnett Shale using public data. There will be examples of MFHWs from the Barnett where the hyperbolic b-exponent will be calculated for each month of production and shown to vary with time as flow regimes change. Single well simulation will be used to characterize the different flow regimes and their effect on decline parameters. Simulation of wells with and without volume outside of fracture tips and their effect on decline parameters will be shown. The decline parameters were in an Arps forecast to match our single well simulation forecast. Uncertainty analysis of production forecast using simulation models is also presented in this work.