The reporting of potential resources is essential to assess the future development plan and profitability of a petroleum discovery, but if the project is under appraised and production data are absent, analysts often use analogs for preliminary estimates of technically recoverable volumes. To address this, a workflow is presented for selecting appropriate analogs for unconventional plays and using them to estimate the target play's potential. The proposed technique is demonstrated with a case study of the as-yet undeveloped Bowland Shale, which is the most prominent of the shale plays in the United Kingdom (UK) and is at the early stage of its assessment. The paper describes the current shale gas activity in the UK, highlighting the enviromental constraints placed on would-be Bowland Shale developers, which impact on drilling and production operations and stem from the geographic proximity of urban developments, infrastructure and nature, which limit the size of well pad footprint in the UK where land use is high. Studies have estimated the play's in-place resources for possible future development, but there are few estimates of its corresponding recoverable volumes due to lack of production history. At the outset, a database is created with published minimum-average-maximum ranges of key parameters such as total organic carbon, maturity level, gas filled porosity, permeability, etc. that play a major role in resources estimation and recovery potential for all unconventional plays. A comparison of triangular distributions, key parameter by key parameter, between the target shale play and the analog database, is then carried out using novel graphical and statistical methods to establish a "confidence factor" relating to the analog's viability. The most appropriate analog for the Bowland Shale is chosen from an exhaustive list of North American shale gas plays. Analytical approaches are then used to transform a model of the published type well performance of the selected analog by exchanging key model parameters with those of the target shale play. The paper shows how UK operational constraints can be statistically incorporated into the workflow and have a marked effect on the estimated recovery from the Bowland Shale.
Operators in the North Sea have been concerned about the ability of the cement sheath to maintain sealing integrity because of the increasing number of reported failures in mature wells. This paper presents results from a new laboratory setup to visualize the source of issues. Many wells in the Cana-Woodford shale suffer from chronic sustained casing pressure (SCP) because of poor cement-sheath bonding. This work demonstrates cement design that includes evaluating cement-sheath mechanical integrity in intercalated salts.
The complete paper discusses the advancements in mud-displacement simulation that overcome the limitations of the previous-generation simulator and provide a more-realistic simulation in highly deviated and horizontal wells. Operators in the North Sea have been concerned about the ability of the cement sheath to maintain sealing integrity because of the increasing number of reported failures in mature wells. This paper presents results from a new laboratory setup to visualize the source of issues. Many wells in the Cana-Woodford shale suffer from chronic sustained casing pressure (SCP) because of poor cement-sheath bonding. As deeper and more complex well designs proliferate throughout oil and gas fields, well completion methods are challenged and new technologies are emerging to ensure safe, cost-efficient, and optimized completions.
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Well RXY is located in Cairn’s Ravva offshore field in the Krishna-Godavari Basin in India. One goal for the field was significant crude production by means of a secondary reservoir section. This paper compares the results of gas identification and lithology identification using pulsed-neutron spectroscopy in openhole and casedhole environments. Acquiring data from an abandoned subsea well has been done before, but never quite like this. As I read through the abstracts and papers that have been presented in the past year, I notice several key themes: verification of cement placement, development of new materials as a barrier, development of new additives to improve the cement barrier, and enhancement of existing techniques.
Africa (Sub-Sahara) Eni discovered gas and condensate in the Nkala Marine prospect offshore Congo. The discovery could hold from 250 MMBOE to 350 million MMBOE in place, the company said. In a production test, the Nkala Marine 1 discovery well in the Marine XII block yielded more than 10 MMcf/D of gas and condensate. Eni is the operator with a 65% interest in the block. The remaining shares are held by New Age (25%) and Societé Nationale des Pétroles du Congo (SNPC) (10%). Sonangol and Total will break ground on a deepwater oil pumping project that will increase Angola's production by more than 30,000 B/D.
Karam, Pierre (Baker Hughes, a GE Company) | Yang, Junjie (Baker Hughes, a GE Company) | Cozyris, Kristian (Baker Hughes, a GE Company) | Stephenson, Tim (Baker Hughes, a GE Company) | An, Xiaoxuan (Baker Hughes, a GE Company) | Jung, Chimok (SK E&P Operations America) | Jun, Jongyoung (SK E&P Operations America) | Lee, Hyungseok (SK E&P Operations America)
Sooner Trend Anadarko Canadian Kingfisher, also known as STACK, is a booming unconventional oil play in North America. As one of the main features that makes the asset profitable, multiple targeting benches raise a challenge of optimization. Well-developed natural fracture system brings in another level of complexity to estimate well spacing. This study introduces an integrated workflow to better understand the fluid flow mechanism in the reservoir and optimize development strategy.
From borehole image log, natural fracture orientation and density was interpreted and statistically populated into geologic model along with petrophysical properties. To account for productivity enhancement due to natural fractures, enhanced permeability was embedded into the simulation model according to the distribution of discrete fracture network. After being history matched, the reservoir model was used to test the sensitivity on well spacing, landing zone and hydraulic fracturing pump schedule. Both infill drilling program and green field development scenarios were tested and compared to optimize our field development study.
Production history match indicates that natural fractures serve as fluid flow conduit and contribute significantly to the production in Osage. Pressure transient observation shows a similar reservoir behavior in the Osage as opposed to the Woodford. Multiple wells experience productivity reduction over longer production history, indicating near-field damage (such as scaling) and/or far-field damage (such as fracture closure). Introduction of skin factor and pressure dependent permeability captured the trend on productivity behavior in the history match. In addition, the simulation study shed light on the hydraulic fracture geometry that provides direct insight on well spacing and landing zone analyses. Results from the infill drilling program show that staggered design with 3 Osage and 4 Woodford wells per section yields the higher oil recovery. However, using the greenfield sensitivities, and depending on the pumping schedule, hydraulic fractures from Woodford wells show upward growth, draining both formations effectively even without Osage wells.
This study provides valuable information about the development strategy in STACK unconventional resources, particularly for scenarios with natural fracture system and multiple targeting zones. The simulation workflow considers well interference in both horizontal and vertical directions simultaneously to optimize oil recovery and reduce operational cost.
One of the considerations in hydraulic fracturing treatment optimization in unconventional (shale/tight/CBM) reservoirs is creating fracture complexity through reducing or possibly eliminating or neutralizing the in-situ stress anisotropy (differential stress) to enhance hydraulic fracture conductivity and connectivity by activating planes of weakness (natural fractures, fissures, faults, cleats, etc.) within the formation in order to create secondary or branch fractures (induced stress-relief fractures) and connect them to the main bi-wing hydraulic fractures. However, actual field experience has shown that some reservoirs under certain treatment designs exhibit excessive fracture complexity due to excessive induced stresses or stress shadowing that can result in pressureout or screenout, and thus, poor well completion and productivity performance. Therefore, it is crucial to identify the reservoir candidates and treatment strategies that are suitable for enhancing fracture complexity to avoid fracturing treatment scenarios that will have an adverse effect on the well productivity.
In this work, a three-dimensional hydraulic fracture extension simulator is coupled with a reservoir production simulator to screen for the reservoir candidates and fracturing treatment scenarios that can lead to enhancing fracture complexity, conductivity, and connectivity and positive well production performance. Furthermore, scenarios are identified under which excessive fracture complexity (due to excessive induced stresses or stress shadowing) results in poor well completion performance.
The results indicate that fracture complexity can be enhanced under the following treatment scenarios: (1) low-viscosity slickwater with smaller proppant sizes under high treatment rates, (2) hybrid fracture treatment (low-viscosity slickwater containing smaller proppants and low proppant concentrations with high treatment rates followed by viscous treatment fluids containing larger proppants and higher proppant concentrations), (3) simultaneous fracturing of multiple intervals at close spacing, and, (4) out-of-sequence pinpoint fracturing (fracturing Stage 1 and then Stage 3 followed by placing Stage 2 between the previously fractured Stages 1 and 3). It is also revealed that the success of each of the above treatment scenarios is very sensitive to rock brittleness (combination of Young's modulus and Poisson's ratio), magnitude of stress anisotropy, matrix permeability, process zone stress/net extension pressure, fracture gradients, and treatment fluid viscosity and rate. Additionally, excessive fracture complexity, which impedes fracture growth due to pressure out and screenout, can be mitigated by reducing treatment rate and pressure, increasing treatment fluid viscosity, and using small particulates, such as 100-mesh proppant.
This work is the first attempt in comparative evaluation of the impact of creating fracture complexity under a variety of operationally-feasible treatment scenarios applied to a wide range of reservoir and rock geomechanical properties. It shows that wells with certain combinations of Young's modulus, Poisson's ratio, stress anisotropy, and fracture gradients are not suitable candidates for creating complexity in the hydraulic fractures system.
Cao, Jinrong (The University of Tokyo) | Liang, Yunfeng (The University of Tokyo) | Masuda, Yoshihiro (The University of Tokyo) | Koga, Hiroaki (Japan Oil, Gas and Metals National Corporation) | Tanaka, Hiroyuki (Japan Oil, Gas and Metals National Corporation) | Tamura, Kohei (Japan Oil, Gas and Metals National Corporation) | Takagi, Sunao (Japan Oil, Gas and Metals National Corporation) | Matsuoka, Toshifumi (Fukada Geological Institute)
In this paper, we present an improved method to predict the methane adsorption isotherm for a real shale sample using molecular dynamics (MD) simulation with a realistic kerogen model. We compare our simulation results both to the experiment and to the simulation results on the basis of a simple graphite model, and show how our procedure leads to the creation of more accurate adsorption isotherms of a shale sample at a wide range of pressure. A Marcellus shale sample was chosen as an example to demonstrate how to calculate the adsorption isotherms using MD simulations. Type II kerogen molecular model was selected for the dry gas window. The constructed bulk kerogen model contains mesopores (> 2 nm) and micropores (≤ 2 nm) inside. Ten different mesopore sizes of kerogen nanopore systems were constructed. According to the characteristics of methane density distribution in the simulation system, three regions can be clearly distinguished, free gas, adsorbed gas, and absorbed gas. We show that the adsorbed gas per unit pore volume increases with the pore size decreased. This is similar to previous molecular simulations with graphite model. For predicting the total adsorption isotherm of a real shale sample, both adsorbed and absorbed gas were considered. For the adsorption amount, the calculated adsorption isotherms were averaged based on pore size distribution of that Marcellus Shale sample. For nanopores smaller than 5 nm, we used total organic carbon (TOC) data to weight the absorption contribution in the kerogen bulk (i.e. inside the micropores). The total adsorption isotherm thus obtained from our simulations reproduced experiments very well. Importantly, kerogen model has overcome the difficulties of prediction using graphite models (i.e. an underestimation of adsorption under high pressure conditions) as documented in previous studies. Furthermore, we predicted the adsorption isotherms for higher temperatures. With the temperature increased, lower adsorption amount is predicted. The novelty of our improved method is that it is able to predict methane adsorption isotherm at a wide range of pressure for a shale sample by considering both adsorption in kerogen mesopores and absorption in kerogen bulk. It can be readily used for any shale sample, where the pore size distribution, porosity, and TOC are known. We remark that the above results and conclusion resulted from our simple assumption. Further discussion might be necessary.
Ma, Xinxing (Oil & Gas Technology Institute of Changqing Oilfield Company, PetroChina) | Kao, Jiawei (State Key Laboratory Petroleum Resources and Prospecting, China University of Petroleum) | Zhou, Zhou (State Key Laboratory Petroleum Resources and Prospecting, China University of Petroleum)
Rock brittleness is a key factor to influence the fracture behavior in the formation. Therefore, it is important to evaluate the brittleness when doing the hydraulic fracturing. Previous studies provided various methods for rock brittleness evaluation. Few evaluations, however, could be applied for the naturally fractured carbonate formation because those methods did not integrate the influence from lithology, natural fractures and vugs. Hence, this paper indicated an integration evaluation method to investigate the brittleness in the naturally fractured carbonate formation.
The rock in this study was from the formation in the Ordos Basin. The brittleness evaluation method asked the experiment studies that included triaxial compression test, continuous strength test, Kaiser test and X-Ray Diffraction analyze. Based on the results, the influence of substrate properties and fractures-vugs in fractured carbonate rock are analyzed. Then a method to evaluate the brittleness of fractured carbonate rock is raised in which the stress-strain curves of rock mechanics tests, geologic microcharacter and the characteristics of fractures are considered. The method can give a better application in Ordos Basin.
The results show that the failure mode of fractured carbonate rock under the effect of confining pressure is mainly the shear failure. The facture will have an obvious effect on the strength of rock. The brittleness of fractured carbonate rock appears as the ability for resisting inelastic deformation before rupture and losing rate of bearing capacity after rupture, besides the minerals of rock and the development of fracture will influence the brittleness. With the increasing of confining pressure, the fractures tend to be closed which leads to the increasing of brittleness. However, the carbonate in high confining pressure is characterized by plasticity, the brittleness would reduce. The brittleness was used to design hydraulic fracturing work in the naturally fractured carbonate formation of Ordos Basin.
Hydraulic fracturing is necessary to guarantee a successful development in the naturally fractured carbonate formation. Therefore, the brittleness evaluation method is worth to study when designing the hydraulic fracturing.