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Pei, Yanli (University of Texas at Austin (Corresponding author) | Yu, Wei (email: firstname.lastname@example.org)) | Sepehrnoori, Kamy (University of Texas at Austin and Sim Tech LLC) | Gong, Yiwen (University of Texas at Austin) | Xie, Hongbing (Sim Tech LLC and Ohio State University) | Wu, Kan (Sim Tech LLC)
Summary The extensive depletion of the development target triggers the demand for infill drilling in the upside target of multilayer unconventional reservoirs. However, such an infill scheme in the field practice still heavily relies on empirical knowledge or pressure responses, and the geomechanics consequences have not been fully understood. Backed by the data set from the Permian Basin, in this work we present a novel integrated reservoir-geomechanics-fracture model to simulate the spatiotemporal stress evolution and locate the optimal development strategy in the upside target of the Bone Spring Formation. An embedded discrete fracture model (EDFM) is deployed in our fluid-flow simulation to characterize complex fractures, and the stress-dependent matrix permeability and fracture conductivity are included through the compaction/dilation option. After calibrating reservoir and fracture properties by history matching of an actual well in the development target (i.e., third Bone Spring), we run the finite element method (FEM)-based geomechanics simulation to model the 3D stress state evolution. Then a displacement discontinuity method (DDM) hydraulic fracture model is applied to simulate the multicluster fracture propagation under an updated heterogeneous stress field in the upside target (i.e., second Bone Spring). Numerical results indicate that stress field redistribution associated with parent-well production indeed vertically propagates to the upside target. The extent of stress reorientation at the infill location mainly depends on the parent-child horizontal offset, whereas the stress depletion is under the combined impact of horizontal offset, vertical offset, and infill time. A smaller parent-child horizontal offset aggravates the overlap of the stimulated reservoir volume (SRV), resulting in more substantial interwell interference and less desirable oil and gas production. The same trend is observed by varying the parent-child vertical offset. Moreover, the efficacy of an infill operation at an earlier time is less affected by parent-well depletion because of the less-disturbed stress state. The candidate infill-well locations at various infill timings are suggested based on the parent-well and child-well production cosimulation. Being able to incorporate both pressure and stress responses, the reservoir-geomechanics-fracture model delivers a more comprehensive understanding and a more integral solution of infill-well design in multilayer unconventional reservoirs. The conclusions provide practical guidelines for the subsequent development in the Permian Basin.
Abstract Hydraulic fracturing is a widespread well stimulation treatment in the oil and gas industry. It is particularly prevalent in shale gas fields, where virtually all production can be attributed to the practice of fracturing. It is also used in the context of tight oil and gas reservoirs, for example in deep-water scenarios where the cost of drilling and completion is very high; well productivity, which is dictated by hydraulic fractures, is vital. The correct modeling in reservoir simulation can be critical in such settings because hydraulic fracturing can dramatically change the flow dynamics of a reservoir. What presents a challenge in flow simulation due to hydraulic fractures is that they introduce effects that operate on a different length and time scale than the usual dynamics of a reservoir. Capturing these effects and utilizing them to advantage can be critical for any operator in context of a field development plan for any unconventional or tight field. This paper focuses on a study that was undertaken to compare different methods of simulating hydraulic fractures to formulate a field development plan for a tight gas field. To maintaing the confidentiality of data and to showcase only the technical aspect of the workflow, we will refer to the asset as Field A in subsequent sections of this paper. Field A is a low permeability (0.01md-0.1md), tight (8% to 12% porosity) gas-condensate (API ~51deg and CGR~65 stb/mmscf) reservoir at ~3000m depth. Being structurally complex, it has a large number of erosional features and pinch-outs. The study involved comparing analytical fracture modeling, explicit modeling using local grid refinements, tartan gridding, pseudo-well connection approach and full-field unconventional fracture modeling. The result of the study was to use, for the first time for Field A, a system of generating pseudo well connections to simulate hydraulic fractures. The approach was found to be efficient both terms of replicating field data for a 10 year period while drastically reducing simulation runtime for the subsequent 10 year-period too. It helped the subsurface team to test multiple scenarios in a limited time-frame leading to improved project management.
Recently unconventional gas resources including the shallow biogenic gas reservoirs have received great attention around the world due to technical advances in the field development and corresponding large in-place resources. However, the technologies needed for the effective development of unconventional reservoirs are still behind the industry needs, for example the gas recovery rates from these unconventional resources are still very low.
The Miocene Gachsaran Formation across Onshore Abu Dhabi and Dubai possesses high potential of generating shallow biogenic gas. To understand and evaluate its capability for a promising gas resources a dynamic model and field development plan were generated based on a detail G&G analysis. The Gachsaran biogenic gas potential falls under the category of unconventional resources due to the existence of adsorbed gas within the organic matter and clay.
The paper provides a detailed numerical simulation approach from a modified commercial simulators to simplify analytical solutions for adsorbed gas in-place calculation and full field development plan. The construction of dynamic model to tackle the growing advances in drilling and stimulation technologies for such complex tight reservoirs have become possible. These reservoirs are still challenging to produce due to their complex geology, tightness and requirements of advance production technologies such as hydraulic fracturing to achieve economical production rates.
The gas flow mechanisms in nano-pores cannot be simply described by Darcy flow equation. In addition, due to large-scale fracturing, the conventional single porosity model is not enough to simulate the characteristics of these source rock type reservoirs. Furthermore, advanced simulation methods such as molecular dynamic simulation are computationally challenging and very time consuming.
To mitigate these challenges, two alternative unique approaches were considered to model these reservoirs: (1) application of analytical methods to characterize the primary characteristics of nano-pores, and (2) extending the conventional simulator to effectively model flow from the nano-pores gas reservoirs. The study describes the theory and application utilized to modify and enhance the capability of conventional simulator. Consequently, to properly estimate the adsorbed gas in-place and integrate the effects of Langmuir gas desorption and gas diffusion effects. Therefore, the dual-porosity model was built and coupled with local grid refinement to capture the associated hydraulic fracture design and properties. This robust modeling approach has provided an enhancement in the field development planning of such a complex regional scale unconventional reservoir.
Wigwe, Marshal E. (Texas Tech University) | Basit, Mohammad I. (Texas Tech University) | Elldakli, Fathi (Priority Artificial Lift Services) | Dambani, Samuel (Belemaoil Production Ltd) | Mmuenu, Rosemary (Saipem Constructing Nigeria Ltd) | Soliman, Mohamed Y. (University of Houston)
Abstract Well placement is a critical aspect of Field development planning in order to fully understand the extent of the field to further effectively develop and drain the field. In most cases, the structure of the formation is initially unknown, in addition to other geologic and petrophysical properties that will aid in calculation of GIIP and EUR. The use of analogy alongside decline curve analysis have been great starting points to drill the first few wells while additional data are being collected to enable the use of more advanced tools like reservoir simulation for full-field development study. This paper presents a study on the production of a gas field and the contributions from seven vertical wells that had been drilled. These seven wells are designated wells p1 to p7. Wells p1, p2 and p6 are located on the anticlines, p3 and p7 are located on the front edge of the reservoir, and p4 and p5 are placed at the center between the two domes. Contour, isopach, isopermx, isopermy and isoporosity maps were used for grid generation, while other modeling software were used for reservoir simulation and visualization. Four base cases were simulated to study the effects of grid sizes and use of local grid refinement (LGR). Four additional "experimental" cases were studied to explore alternative well placement and potential benefit for horizontal and hydraulically fractured wells. The two poor performing wells (p3 & p7) were considered as good candidates for hydraulic fracturing. Unfortunately, the results were not promising as both wells showed less than 1% improvement in gas recovery and hence may not justify the investment. The use of alternative well placements scenarios for these wells resulted in about 9% incremental recovery while conversion to horizontal wells added a further 3% in recovery. This last investment will be further justified if a dual lateral is considered rather that two separate wells.
Hren, Agustin (Weatherford Internacional de Argentina) | Exler, Victor Ariel (Weatherford Internacional de Argentina) | Peacock, Horacio (Weatherford Internacional de Argentina) | Schmidt, Roberto (Weatherford Internacional de Argentina) | Pellicer, Marcelo Daniel (Pan American Energy LLC) | Lamberghini, Lucia (Pan American Energy LLC) | Gait, Jorge (Pan American Energy LLC)
Abstract Lindero Atravesado field is located in Neuquen, western Argentina. It has been under development since 2012. Originally, its development was focused on conventional formations (Quintuco, Sierras Blancas and Lotena), considering the Punta Rosada and Lajas formations as geological traps. Development is now focused on these traps, especially in the northwest region the field, called the Lindero Atravesado Occidental. Fundamental challenges in the Occidental region of the field include optimum fluid engineering, avoiding shear-sensitive fluid systems, high PAD percentage and safe operational efficiency in deep HPHT wells. However, original frac designs were optimized through a traditional cycle of design and pressure-matching evaluations using a conventional frac simulator. Obtained fracture geometries were bounded in length and a considerable height growth was observed. Other studies used microseismic, sonic profiles or traceable sands, and showed fractures contained in height and longer fracture lengths than those obtained with the traditional adjusted model. A fracturing model coupled with microseismic interpretation allowed a better characterization of fracture geometry, vertical covering, effective production fracture length and drainage area efficiency, based on numerical production simulations and matching. The last point will have a direct impact on well spacing and future selection of in-fill locations. This paper will discuss a fully integrated approach for field planning optimization, starting with geosciences characterization, workover, stimulation and production history matching, with a direct impact on well gridding and estimated ultimate recovery (EUR) per well.
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.
Recent advances in hydraulic fracture mapping technologies have provided a wealth of information on fracture propagation in numerous geologic settings. Prior to such detailed measurements of actual fracture growth, fracture propagation was either assumed to be simple (single planar fracture) or the complexity was inferred based solely on fracturing pressure data. The nature or detail of this inferred fracture complexity and how it related to actual fracture growth (real fracture geometry) could not be determined. This resulted in significant uncertainty in fracture modeling, treatment designs, and many times, sub-optimum field development. This paper illustrates the application of the various methods and techniques available to diagnose fracture complexity, including simple pressure diagnostics such as G-function pressure decline analysis and sophisticated microseismic and tiltmeter fracture mapping technologies. After identifying complexity in hydraulic fracture growth, this information must be integrated with fracture, reservoir, and geologic models to properly evaluate stimulation, completion, and develop options; however, without properly identifying the nature and detail of the fracture complexity, the solution can many times be wrong - resulting in economic loss.
This paper documents field observations of different mechanisms that result in fracture complexity and the corresponding physics that govern fracture growth in these reservoirs. These field observations of fracture complexity are supplemented by and related to results from mine-back and core-through experiments to better understand the relationship between fracture complexity, rock properties, and geology. Distinguishing between the various types of fracture complexity and properly modeling these complexities (in both reservoir and fracture models) can lead to significantly different treatment designs and field development strategies. The paper includes field case histories that document how the remediation of fracture complexity can lead to stimulation success, while in other cases it is the exploitation of fracture complexity that is the key to success.
Thus the total wave field is a sum of the computation of the traveltimes and raypaths in highly heterogeneous media.