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Optimum subsurface well spacing is key to developing unconventional reservoirs. From a field application perspective, this paper presents our systematic study on subsurface well spacing in the Permian Basin for unconventional reservoirs which consisted of four main components, i.e., numerical modeling, well interference quantification through simulation and regression, field pilot analogs, and economic evaluation. In this paper, field pilot wells are actual wells in the field to test different well spacing and completion designs. To capture upsized and downsized completions, a wide range of fracture designs in combination with different well spacing scenarios are conducted for both hydraulic fracture modeling and reservoir simulation. At the section level (1 mile by 1 mile, 640 acres), multiple wells are simulated to better capture well interactions and reservoir property variations. A complex fracture network is generated by considering interactions between natural fracture and hydraulic fracture. Well interference, which is determined by estimating ultimate recovery (EUR) difference between a single well and a middle well from multiple wells, is analyzed for general trend regressions and validated through field test results. At the section level, economics is done to evaluate capital efficiency of various scenarios. Results from both modeling work and pilots indicate that larger hydraulic fracture size without an increase in subsurface well spacing does not necessarily improve section EUR and there is a point of diminishing returns. Larger subsurface well spacing with bigger fracture size is thereby a preferable combination.

Summary It is important to determine several key parameters, such as well spacing, completions design, landing strategy, and pad sequence, for a successful full-field development of the unconventional reservoir that involves multiple wells and pads in a given area of interest. Those parameters are normally considered individually through small and simple models. In this paper, focusing on developing the whole area effectively, we provided a systematic work flow to handle such challenges together: We first recommended a top-down concept that better represents actual field development and illustrates the importance of the 3D Earth model for the unconventional reservoir; we then proposed an integrated modeling that is an iterative loop consisting of the 3D Earth model, hydraulic-fracture modeling, reservoir simulation, and uncertainty analysis. It is uncommon to build a 3D Earth model for the unconventional reservoir mainly because of the lack of data and software capability. In this paper, we provided a cost-effective approach for the first time on the basis of a large amount of existing vertical wells, newly drilled horizontal wells, and all the data available. A 3D Earth model using information from approximately 1,100 vertical wells from the Midland Basin was presented. Such a model has a high resolution conditioned by high well density, and has an advantage of capturing heterogeneities and interactions more than a simplified model created either from one well or low-resolution seismic interpretation. The model was fed into hydraulic-fracture modeling with the consideration of natural-fracture network and stress shadow, followed by reservoir simulation. The in-house uncertainty-analysis package that functions by experimental-design philosophy is linked to the Earth model, hydraulic-fracture modeling, and reservoir simulation. For the first time, the impacts of all the parameters together were evaluated through the final production performance. In our example, we considered completions design, discrete-fracture-network (DFN) characterization and generation, unpropped hydraulic-fracture properties, fracture compaction, and matrix permeability. The result indicated that DFN characterization is the most important parameter affecting production performance. We applied our model and work flow to field development. Well spacing and pad sequence were studied in this paper as two examples. We demonstrated that it is important to properly consider complex interactions among multiple clusters, stages, and wells to evaluate the impacts on well spacing, completions, and development sequence.

Hydraulic fracturing is a stimulation treatment routinely performed to create fracture network on low permeability reservoirs to enhance the productivity. Such induced fracture network has much higher conductivity and generally is treated through either local grid refinement (LGR) to capture the transient phenomenon or embedded discrete fracture model (EDFM). Both approaches require complex gridding meshes, leading to heavy computational time. LGR also requires the orthogonal orientation of hydraulic fracture with horizontal wellbore trajectory. Another challenge for LGR and EDFM comes from the dynamic meshing over the time. Infill drilling and re-fracturing are common due to the nature of the fast production decline in those hydraulically fractured wells. In the case of infill drilling or re-fracturing, the grids for the well or completion stages have to be generated from the beginning of the simulation, causing computational inefficiency. Also, sensitivity evaluation of well landing point, spacing, and completion optimization needs easy preprocessing of model input and short simulation time. In this paper, we overcome the above challenges through representing hydraulic fracture network with multisegment well (MSW) concept. Multisegment wells (MSW) offer an improved description of the wellbore physics over conventionally modeled wells and can be used in different situations like, horizontal or multilateral wells, wells with inflow control devices (ICDs), and significantly varying flow conditions along the wellbore. On the other hand, the conventional well model (CWM) represents a well as a single pipe (single fluid) a MSW discretizes the well trajectory into several segments. Each segment has its fluid conditions and solution variables, hence allowing for detailed modeling of changing conditions along the wellbore. Since MSW node system is independent of reservoir grid system, fracture orientation can be at any angle freely with wellbore trajectory, which avoids the complex LGR or EDFM and reduces the number of grids. Meanwhile, MSW provides a flexibility of fracture geometry representation, enabling easy addition and alteration of fractures at any simulation time. Our MSW approach has been validated by comparing with the LGR through several benchmarking studies of a tight reservoir. A field case was demonstrated for infill drilling among existing vertical wells and re-fracturing operations. While it is difficult to model infill drilling of a well with hydraulic fractures through another modeling approach, the MSW option makes it easy by just opening the wellbore with fractures at certain simulation time. The re-fracturing operation is modeled as the opening of the completion. These settings can be done for each well. Our approach also has potential to dynamically couple with stimulation design tools.

•An improved upscaling and simulation method for composite gas reservoirs with interbedded shale and tight sandstone.•We regard the two types of rocks as dual porous media to replace single porous medium used in the traditional methods.•The primary- and secondary- hydraulic fracture are modeled as discrete fracture and continuous medium respectively.•The method can avert the challenge of upscaling the parametric curves of different rocks.

Fracture networks present a critical influence on to better assess oil recovery and to optimize production of hydraulically fractured reservoirs. We established a novel workflow for fracture uncertainty analysis and prediction, in which multiple fracture pattern realizations are created from the geostatistical analysis. The original fracture networks were created using geomechanics tools. Then the fracture network is reconstrued for uncertainty analysis and history matching. For different realizations of the fracture distributions created in this workflow, we successfully maintain the continuity of the fractures, as well as the connections from the matrix to fractures. The generated grid can be further used for treatment simulation to determine fractures geometry, height growth and respected proppant transport in the induced fracture network. In this paper, we also apply Embedded Discrete Fracture Model (EDFM) to capture the realistic geometry of fractures. Within the EDFM, each fracture plane is embedded inside the matrix grid and is discretized by the cell boundaries. We study a series of reservoir simulation realizations, in which the complex hydraulic fracture networks are created in the workflow. We investigate different fracture realizations in both planar and complex fracture configurations while maintaining the continuity within the fracture networks. This study also includes the influence of the network geometry and fractures properties on the overall performance of the reservoir. From the uncertainty analysis results, we find that the overall reservoir performance is controlled by the fracture connectivity and the distribution of conductivity within the network. A good match of production history can be achieved by adjusting the fracture connectivity. Modeling with multiple realizations of fracture networks acknowledge that a reliable production forecast is achievable using geostatistical analysis for fracture connection reconstructions. Applying Embedded Discrete Fracture Model (EDFM) on the fracture-related model simulation provides a robust and effective means of investigating multiple fracture realizations.

A snake well is a complex well type and meanders in a sinusoidal pattern through multiple drainage areas provided by multiple isolated production zones. Conventional productivity calculation methods for horizontal wells could not be applied directly for snake wells because the production segments in the wellbore have large vertical fluctuation and wellbore pressure drop is noticeable. Starting from the distribution of velocity potential produced in an infinite reservoir by one snake well, this paper uses mirror image and the principle of superposition to obtain velocity potential and pressure distributions in bottom water drive reservoirs with and without gas cap, and edge water drive reservoir. Flow characteristics along the wellbore are then investigated and a pressure drop model is developed. Coupling the flow inside wellbore and in the reservoir, we developed and further solved a productivity prediction model for the snake well. The proposed approach to calculating well productivity better meets the reality and results in more accurate prediction. Case studies in bottom water drive reservoir with and without gas cap, and edge water drive reservoir show that snake wells with small fluctuation rates yield higher productivities than horizontal well. Also, permeability anisotropy has less impact on the productivity of snake well than that of horizontal well. For the reservoir with low vertical permeability, snake well can perform better than horizontal well.

Barrier impacts on water cut and critical rate of horizontal wells in bottom water-drive reservoirs have been recognized but not investigated quantitatively. Considering the existence of impermeable barriers in oil formations, this paper developed a horizontal well flow model and obtained mathematical equations for the critical rate when water cresting forms in bottom-water reservoirs. The result shows that the barrier increases the critical rate and delays water breakthrough. Further study of the barrier size and location shows that increases in the barrier size and the distance between the barrier and oil-water contact lead to higher critical rates. The critical rate gradually approaches a constant as the barrier size increases. The case study shows the method presented here can be used to predict the critical rate in a bottom-water reservoir and applied to investigate the water cresting behavior of horizontal wells.

Liquefied petroleum gas (LPG) refers to the gas extracted and liquefied from the separator gas in a processing plant and mainly consists of propane (C3) and butane (C4). Many offshore projects have restrictions on flaring gases and special fiscal terms make extracted liquids significantly more valuable than oil and condensate in some cases, which in turn impact the economics of many projects. This paper for the first time systematically investigates LPG characterization and production quantification coupled together with reservoir simulation. Detailed calculations of LPG yields from both gas cap and solution gas are given. LPG yield of fluid is a function of the initial gas–oil ratio (GOR), gas specific gravity, and separator condition: LPG yield, which is lower in the gas cap compared to the solution gas of the same reservoir, has a good correlation with gas specific gravity and is impacted by separator conditions. The concept of LPG-produced GOR correlation curve is introduced and applied together with gas production rate to predict LPG production. Correlation curves depend on reservoir fluid properties and development strategies. Generated from flashing the mixtures of different proportions of oil and gas samples, LPG-produced GOR correlation curve has a good agreement with the results from reservoir compositional simulation and can be coupled with various forecasting tools in reservoir engineering. Lean gas injection has an insignificant impact on LPG recovery but can substantially improve the recovery of total liquid (oil and condensate). The paper also shows that lumping C3 and C4 as one pseudocomponent is suitable.

Chevron has performed surveillance, analysis and optimization (SA&O) pilot study in its Midland Basin Wolfcamp tight oil development area. In this paper, we will focus on the pilot overview, production logs, rate transient analysis (RTA), and multiple well interference pressure transient analysis (PTA). The pilot area consists of a center 20-acre vertical well and four pressure monitoring wells in four directions with a distance of 460 ft to the center well. Production is commingled by 8 hydraulically fractured stages. Four-array downhole microseismic shows the shape of reservoir stimulation. Each vertical monitoring well is equipped with 8 permanent downhole gauges with packers isolating 8 layers, and the real-time data is acquired through SCADA (Supervisory Control and Data Acquisition) system. Multiple production logs have been acquired in the center well during the earlier natural flow period. RTA has been performed in the center well based on the production rate measured from a dedicated test separator, flowing bottomhole pressure from a downhole memory gauge, and zonal contributions from production logging (PLs). PLs show that fluid comes primarily from the Spraberry, secondly from the Lower Wolfcamp, and some from the Strawn and Atoka. The RTA shows that effective drainage area of the well is less than 20 acres. In addition, fracture half-length and effective permeability are degrading with time, which impacts the well's EUR. The acquired pressure responses in observation wells have been studied with non-linear numerical model in PTA to better characterize the fracture network and reservoir. It shows a high possibility of connecting with neighbor wells in certain formations and exhibiting characteristics of time-dependent fracture closing. Production performances with original 40-acre spacing wells and recently drilled 20-acre infilled wells are compared, indicating that 20-acre wells helps to improve oil recovery and economics. The center well was shut in for more than 9 months to get buildup data. During the 5 month post shutin production (PSP), the well had significantly higher oil rate and positive net oil recovery with decreased GOR and water-cut. The pilot sheds light on first principles and tight oil development strategy. Accurate microseismic data, production logs, interference well testing, and rate transient analysis are powerful tools for unconventional studies.

The selection of perforation zones in unconventional reservoirs can be very challenging. Great strides have been made by the integration of both engineering and geological data. However, a successful perforation zone selection methodology in one Basin might not be successful in another. This paper presents a pilot study on a perforation zone selection and zonal contribution in a vertical well in the Midland Basin. Reservoir characteristics as well as the geomechanical properties of a formation are important in the selection of optimum locations for limited entry perforations. In this work, several data sets, including openhole logs, radioactive tracer logs, amount of proppant pumped, PVT sampling, and 3D fracture modeling were integrated. Additionally, temperature logs were used to identify zonal contributions during the early flowing period. Results from this work indicate that closure stress is the dominant parameter greatly affecting the fracture initiation and growth in the observed well while both high and low brittleness sections were observed similar behavioris of hydraulic fracture failure. Learnings from radioactive proppant tracers and 3D fracture modeling efforts helped to identify the importance of closure stress in addition to brittleness in perforation placement identification. Temperature log interpretations were correlated with proppant tracers and fracture modeling which qualitatively indicates that the Lower Spraberry and Wolfcamp B formations are big contributors to production and thus good potentials targets for horizontal wells.

The Greater Vanza Longui Area (GVLA) field is located in Area B of the offshore Cabinda, Angola Block 0 concession. GVLA is a multi field development and will target hydrocarbon resources in the Cretaceous Pinda formation that contain reservoirs with rich gas condensates and underlying volatile oil rims. The objective of this paper is to demonstrate the rigorous subsurface evaluation process employed for developing a large offshore gas condensate field. The strength of the reservoir evaluation is the large amount of good quality appraisal data gathered and used to benchmark subsurface inputs. There have been 6 reservoir penetrations, 4 DSTs and 3 full reservoir cores and multiple fluid samples. A structured workflow was followed to identify and incorporate the uncertainties in the subsurface assessment. Probabilistic forecasts helped to fully characterize and realistically assess the uncertainties. The uncertainties were grouped mainly into static and dynamic categories. The impact of the static uncertainties was assessed using 3-D geological models. Geologic models were built upon a core-based sequence stratigraphic framework for the Pinda formation. The facies, petrophysical properties and top depth of reservoir were varied to capture the uncertainty ranges seen in the GVLA wells and analogue fields. These models captured the net-to-gross uncertainty which has the largest impact on hydrocarbons in-place and connectivity. The dynamic uncertainties were assessed using statistical design of experiments. Monte Carlo simulations were employed to generate the probabilistic estimates. Reservoir simulation with the compositional formulation was used as the primary forecasting method. Robust equation-of-state models were built to appropriately quantify natural gas liquids (LPGs) which were value drivers for the project. Various development alternatives (primary depletion, gas injection) were evaluated and detailed economic analysis were performed for concept selection. The production forecasts were verified with material balance models, analogues.

Deep gas-condensate reservoirs, with high temperature, high pressure, and low permeability, account for a high proportion in the recent years. Quite different with conventional gas-condensate reservoir, this type of reservoir has smaller rock grains, prominent interfacial phenomena, and appreciable reservoir deformation. Consequently, it is necessary to study phase behavior and well productivity to model these deep gas-condensate reservoirs more accurately. This paper considered both interfacial effect and reservoir deformation, and proposed a new method for calculating oil-gas phase equilibrium in deep gas-condensate reservoirs. We introduced phase equilibrium calculation into fluid flow theory for condensate oil and gas system and then mathematically developed a physical-chemical flow model with consideration of interfacial effect and reservoir deformation. Gas well productivity was also studied and the corresponding equation was derived. Because flow behavior near wellbore is essentially important for a gas-condensate reservoir, we investigated fluid flow near wellbore and provided methods to determine retrograde condensate saturation, gas relative permeability, and pressure distribution. We applied to a real gas condensate reservoir and calculated well productivity, retrograde condensate saturation distribution, and gas relative permeability, particularly near wellbore. The results illustrated that interfacial phenomena and reservoir deformation made retrograde condensation appear much earlier and consequently aggravate formation damage. Therefore, the decrease of gas relative permeability and the drop of well production are faster than usual.

In recent years, many gas condensate and volatile oil reservoirs have been discovered offshore. Many of these reservoirs are under high temperature and high pressure conditions. It is important to properly model and optimise gas condensate recovery during asset development in many oil and gas companies. A systematic approach to modelling gas condensate and volatile oil reservoirs by the use reservoir simulation is presented in this paper. The following topics are focused in particular