Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Results
Abstract Due to current economic constraints on companies' capital expenses, the lack of reservoir characterization information has become a challenging issue. As a result, reservoir engineers must make the most of the available data and estimate the reservoir characteristics that are not available. Porosity is typically used to estimate permeability through classical correlations during core analysis. However, due to the effects of complex lithology and pore geometry, it becomes unreliable to predict permeability solely from porosity and using classical relationships. The objective of this study is to enhance the Tortonian reservoir description in Gamma oil field by testing the integration of Flow Zone Indicator (FZI), Artificial Neural Network (ANN), and Convergent Interpolation (CI) techniques. The study utilized data from one exploratory well and four appraisal wells to model the non-linear relationship between the Tortonian reservoir properties, calculate the effective porosity, estimate the permeability of uncured wells, and create a permeability map for the Tortonian oil reservoir. The results showed that there are three rock types in the Tortonian reservoirs, and effective porosity and permeability logs were successfully estimated. The permeability map created showed a direct relationship with the porosity map, validating the methodology. The reliability of the porosity/permeability relationship increased to 90% after using the integrated techniques presented in this study. By integrating FZI, ANN, and CI techniques, this study has successfully modeled the non-linear relationship between the porosity and permeability of the Tortonian reservoir, enabling an economical improvement in the complex reservoir description with minimum capital budget and available data.
- Asia (0.69)
- Europe > United Kingdom > North Sea > Northern North Sea (0.36)
- Europe > United Kingdom > North Sea > Northern North Sea > South Viking Graben > Block 9/19b > Gamma/Losgann Field > Frigg Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > South Viking Graben > Block 9/19b > Gamma/Losgann Field > Balder Formation (0.99)
- Asia > Middle East > Iraq > Basra Governorate > Arabian Basin > Widyan Basin > Mesopotamian Basin > Luhais Field > Zubair Formation (0.99)
- (2 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Neural networks (1.00)
Incorporating Hybrid Technology of CSS + Foam in Heavy Oil Field Development Plans: Practical Experiences and Lessons Learned
Perez, R. A. (Ecopetrol, S.A., Bogotá, Colombia) | Rodriguez, H. A. (Ecopetrol, S.A., Bogotá, Colombia) | Romero, J. E. (Ecopetrol, S.A., Bogotá, Colombia) | Alvarez, J. S. (Ecopetrol, S.A., Bogotá, Colombia) | Hernandez, S. (Ecopetrol, S.A., Bogotá, Colombia) | Luque, I. (Ecopetrol, S.A., Bogotá, Colombia) | Cadena, M. (Ecopetrol, S.A., Bogotá, Colombia) | Ricardo, M. (Ecopetrol, S.A., Bogotá, Colombia) | Barrios, H. (Ecopetrol, S.A., Bogotá, Colombia) | Villadiego, D. (Ecopetrol, S.A., Bogotá, Colombia) | Garcia, J. C. (TIP Colombia, Bucaramanga, Colombia) | Cipagauta, J. A. (DTH Colombia, Bucaramanga, Colombia) | Rondon, M. (DTH Colombia, Bucaramanga, Colombia) | Manrique, E. (Ecopetrol, S.A., Bogotá, Colombia)
Abstract Using preformed foams to improve cyclic steam stimulation (CSS) has been under study by Ecopetrol since 2018. The research and development project included laboratory evaluations to select a foaming agent, a detailed well selection using reservoir engineering and simulation analysis, the development of a wellhead device to preform a stable foam at surface conditions, well treatment design, injection schedule, and technological monitoring tests. The field results showed benefits in incremental oil production, energy efficiency improvements, and carbon intensity reduction. Based on those outcomes and trying to extend the production life of mature assets, the hybrid technology of CSS + Foam improvements was incorporated into the heavy oil field development plans of the Middle Magdalena Valley basin (MMV), Colombia. In the last year, more than thirty (30) wells have been injected with preformed foam improvement before the steam cycle. The methodology includes preinjection laboratory evaluations to mitigate emulsion formation or compatibility problems, well selection and performance forecast, a wellhead device to control fluids (foaming agent and nitrogen) to generate the foam, and the chemical and geochemical surveillance process. Based on the field experiences, a description of the results in terms of incremental oil, energy efficiency, carbon intensity, and protocols of QAQC of injected foam and produced fluid are presented. Systematic monitoring of oil production response showed that most wells reported 50% incremental oil production (2,000 – 4,000 stbo/cycle) from baseline, more than 60% improvement in energy efficiency (MMBTU/stbo), and a 50% reduction in carbon intensity (CO2/stbo) by extending steam cycles (> 6-12 months). Additionally, the chemical analysis indicated that no residual foaming agent was detected in production, which avoids emulsions and problems in production facilities that represent the costs of additional chemical additives. The methodology developed to control foaming generation (water injection rate and foaming agent concentration) led to a high-quality and stable foam. This study shows a novel and representative insight into the best practices and recommendations to implement and monitor CSS + foam plans as a strategy to improve oil recovery in mature wells and avoid stranded assets in agreement with the energy transition plans.
- South America > Colombia > Antioquia Department (0.48)
- South America > Colombia > Santander Department (0.34)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.54)
A Game-Changing Strategy to Increase the Production Tubing Run Life in a Highly Carbon-Dioxide Corrosive Environment: Shushufindi-Aguarico Fields Case Study
Romero, C. (Tenaris, Quito, Ecuador) | Estevez, D. (Tecpetrol, Quito, Ecuador) | Espinosa, C. (Tenaris, Quito, Ecuador) | Freire, C. (EP Petroecuador, Quito, Ecuador) | Sierra, M. C. (SLB, Quito, Ecuador) | Aguilar, L. (SLB, Quito, Ecuador) | Rodriguez, R. (Tenaris, Quito, Ecuador) | Sepulveda, W. (SLB, Quito, Ecuador) | Somale, J. (Tecpetrol, Quito, Ecuador)
Abstract Since the beginning of production in Shushufindi Field, Ecuador, one of the main reasons for well intervention has been issues with the production tubing integrity. More than 30% of production tubing failures were related to corrosion in the tubing, generating additional operational expenditures and production losses. Our strategy to increase the production tubing run life in the field is presented. In 2020, an incremental increase in field production was also accompanied by an increase in production tubing failures. Based on failure analysis that included laboratory tests, information analysis, run-life history, and simulations to predict the corrosion velocity, it was possible to identify the critical wells and to migrate the tubing grade from a L80Cr1 to a grade with 3% chromium (Cr) and maintain the use of an internal flush connection. Before 2018, the common material used for the tubing in Shushufindi was carbon steel API N80.Q and the connection was API EU. Since November 2017 the failure index started to increase, leading to the massification of the grade L80 with 1% Cr content and an internal flush premium connection. In 2020, the total production volume losses attributable to production tubing problems were 8%, and the average run life of wells that failed because of production tubing integrity was less than 400 days, compared to electric submersible pump (ESP) failures. With the massive implementation of 1% Cr steel grade in 2018 and an internal flush premium connection in the tubing, the failure index was reduced from 0.33 in July 2019 to 0.14 in January 2021. However, the use of reused pipe and the strategy to increase production in the field by commingling formations and upsizing the pumps, created a more demanding condition, and induced new tubing failures. With these new operating conditions, a strategy to mitigate early failures was to install tubing with 3% Cr content in seven critical wells. By now the tubing run life had been doubled in two wells and overlapped the previous run life in four wells. Using a 3% Cr-grade tubing has helped to reduce the interventions by three times, and production losses have been reduced by 72,000 bbl. An opportunity to reuse pipe was identified when the tubing was recovered in perfect condition in a pullout caused by an ESP failure after 200 days. Currently (February 2023) the failure index due to communication tubing casing is 0.06.
- South America > Ecuador > Sucumbíos Province (0.72)
- South America > Ecuador > Napo Province (0.72)
- South America > Ecuador > Sucumbíos > Oriente Basin > Shushufindi Field > Napo Formation (0.99)
- South America > Ecuador > Orellana > Amazon Basin (0.99)
- South America > Ecuador > Napo > Oriente Basin > Shushufindi Field > Napo Formation (0.99)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Well Completion > Completion Installation and Operations (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
Innovative Hyperbolic Cutting Structure Brings Step Change in Drilling Efficiency Onshore Mexico
Rosique, P. (SLB, Villahermosa, Tabasco, Mexico) | Anguiano, S. (SLB, Villahermosa, Tabasco, Mexico) | Tocantins, J. P. (SLB, Houston, Texas, USA) | Ross, J. (SLB, Calgary, Alberta, Canada) | Luna, O. (SLB, Villahermosa, Tabasco, Mexico)
Abstract The discovery of field T in Mexico represented the largest such find in a generation. Hence, drilling activity has been focused primarily on economically viable ways to develop these reserves. The reservoir poses several drilling challenges, such as lack of drill bit cutting structure, durability, and aggressiveness leading to unwanted bottomhole assembly trips. These challenges lead to increased well construction costs. Accordingly, an application-specific bit design needed to be developed to optimize drilling efficiency in this section.
- North America > United States > Texas (0.47)
- North America > Mexico > Tabasco (0.28)
- Phanerozoic > Mesozoic (1.00)
- Phanerozoic > Cenozoic > Paleogene (0.94)
- Geology > Geological Subdiscipline > Geomechanics (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.48)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.46)
- Well Drilling > Drillstring Design (1.00)
- Well Drilling > Drilling Operations > Drilling optimization (1.00)
- Well Drilling > Drill Bits > Bit design (1.00)
Abstract Enhanced oil recovery technique for carbonate or sandstone reservoirs using inflow control technology are often affected by undesired production of water and gas. Limited density and viscosity differences between oil, water and gas is often a challenge for most autonomous and passive inflow control technology due to limited fluids performance ratio between oil, water and gas when breakthrough happen. The fluid performance ratio describes how the ICD (Inflow Control Device) and AICD (Autonomous Inflow Control Device) preferably choke the unwanted fluid (water/gas) compared with oil. Different ICD/AICD are utilizing both density and viscosity that effect the flow behavior difference in the valve to differentiate the pressure drop for oil, water, and gas. Different designs have been tested in single phase and multiphase full-scale flow loop testing that replicates downhole operating conditions. In order to understand the ICD/AICD behavior in reservoir environments for the duration life of the well, a wellbore model where the effect of fluids performance ratio is included. The model also includes the effect of mobility ratio and how this affects the importance of the fluid performance ratio. Well completion has a critical role to optimize the well performance and enhanced oil recovery. In today’s engineer toolbox, a wide variety of inflow control technology completion options are available including various ICD and AICD. A new methodology and workflow have been developed to compared different type of inflow control technology completion to understand the capability to reduce unwanted water and gas production without needing detailed information about rock property variation along the wellbore in the reservoir. These methods are based on laboratory flow performance data from each device and will compare various downhole inflow control tools based on their fluid phase performance ratio to produce oil, choke water and/or gas and express the fluid preference by ratio in percentage. Experimental flow loop results illustrate a significant different in fluids performance ratio of conventional ICD and AICV. AICD with dynamic flow area are choking water breakthrough more effectively, resulting in better sweep along the wellbore section that were not previously being produced. By limiting the water and gas production operators are therefore able to apply higher drawdown to increase oil recovery significantly. This improves the economics of thin-oil rim development and benefits of reduced environmental impact per oil produced due to less un-needed water and gas being produced to surface.
- North America > United States (0.28)
- Europe > Norway (0.28)
- Europe > Norway > North Sea > Northern North Sea > South Viking Graben > Vana Basin > RL 088 BS > Block 25/4 > Alvheim Field > Lista Formation > Våle Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > South Viking Graben > Vana Basin > RL 088 BS > Block 25/4 > Alvheim Field > Lista Formation > A2 North Heimdal T60 Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > South Viking Graben > Vana Basin > RL 088 BS > Block 25/4 > Alvheim Field > Hermod Formation > Våle Formation (0.99)
- (21 more...)
- Well Completion > Completion Monitoring Systems/Intelligent Wells > Flow control equipment (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Strategy to Manage Mature Oilfields with Renewable Energies
Quintero, E. (TecnoPetrol, Ingenieros Consultores, Maracaibo, Zulia, Venezuela) | Valdirio, J. (PDVSA, Caracas, Distrito Capital, Venezuela) | Bastardo, J. (PETROZAMORA, Lagunillas, Zulia, Venezuela) | Huerta, V. (Universidad Nacional de Ingeniería, Lima, Perú) | Lorbes, H. (Instituto Universitario Politécnico Santiago Mariño IUPSM)
Abstract In the case of the Venezuelan Maracaibo Lake Basin, the existence of mature represents a good opportunity to recover them using renewable energy, even worldwide exploration efforts become are almost inaccessible and environmentally sensitive places. Therefore, many companies have shifted his strategies to revitalize mature fields, increase their recovery factor and extend their life cycle. This study proposes an integrated approach to revitalize mature fields, but in a sustainable way. by incorporating renewable sources to supply part of the energy field consumption; thus, allowing monetizing more oil (usually used as fuel consumption), and improving asset management by implementing a production monitoring system (based on field automation and remote-control processes). The integrated approach to revitalize mature fields includes the following steps: Reserves management upon best practices recommended in PRMS 2018 and follow up based on performance and sustainability indicators. Artificial lift technologies to optimize production performance. Identification of potential opportunities to substitute fuel consumption with renewable energy sources; incorporated to production optimization, energy efficiency and remote monitoring programs. Implementation of energy transition programs focused on maximizing asset value and improving corporate reputation. It should be noted that Solar and Eolic energy sources were preliminarily identified as the best suited to contribute with revitalization of mature fields, by substituting in between 10 to 15% of fuel consumption; besides this, uncertainty in renewable energy supply, as well as "the state of the art" technologies to extend energy storage should be take into consideration for implementing energy transition programs. In addition, future applications of renewable energy sources in EOR projects may be further investigated considering the benefits in production performance and reservoir management.
- Asia (1.00)
- South America > Venezuela > Zulia > Maracaibo (0.26)
The Use of Machine Learning to Estimate Key Properties in Vaca Muerta Play
Bernhardt, C. (YPF S. A, Argentina) | Horowitz, G. (YPF S. A, Argentina) | Gallart, D. (YPF S. A, Argentina) | Cambra, J. N. (YPF S. A, Argentina) | Silka, M. (YPF S. A, Argentina) | Sanchez, M. G. (YPF S. A, Argentina) | Lopez, L. L. Vera (YPF S. A, Argentina)
Abstract The evaluation of shale reservoir requires solving key properties: total organic carbon (TOC), porosity (PHIT) and water saturation (SW). The determination of these properties with precision, requires laboratory data and high-tech logs. In Vaca Muerta play, the most legacy wells do not have this data. This work presents the Machine Learning as a methodology to estimate TOC, PHIT, cementation factor (M) and saturation exponent (N) with basic logs. Synthetic logs are generated with different predictive models, taking readily available conventional wire logs as input data (Resistivity, Density, Sonic and Neutron). Regarding of PHIT and saturation parameters (M and N), the models are trained with wells in which these logs are available; in the case of TOC, measures in core are used. Once the target log has been defined, an exploratory analysis is carried out. These results feed the machine learning models. The different models are trained and validated, to obtain the best result. For each synthetic log, a 90% confidence interval is also calculated. Linear and non-linear models are developed, and their effectiveness is measured by dividing the data randomly, using 80 % of the data as a training set and the remaining 20% as validation set. Moreover, the validation "leave one out" is also performed. The models are applied to more than 170 vertical wells, in all cases, the synthetic curve is accompanied by a confidence interval. The results of these confidence intervals show that the synthetic logs have a precision that makes them reliable and relevant for decision-making by the specialist. The implementation of this technique provides relevant information for landing zone definition, making maps and volumetrics of greater areal detail. The application of machine learning techniques for the generation of synthetic logs is a procedure that has recently begun to be used in the oil and gas industry. In the particular case of the Vaca Muerta oil field, the series of synthetic logs developed and tested in this work is a complete novelty.
- Geology > Geological Subdiscipline (0.47)
- Geology > Rock Type (0.36)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Field > Vaca Muerta Shale Formation (0.98)
Abstract The Choke Model is an approach to determine well potential after considering all the production system constraints. It is designed to identify production losses, network bottlenecks, and optimization opportunities. This paper shares the digital generation of the Choke Model for a mature field. The core components of the model are production potential estimate; production accounting; shortfall accounting and opportunities materialization. The solution leverages the already deployed cloud systems to define the individual choke capacity —reservoir, well, plant, export and, commercial—. A combination of in-house coding and industry-standard software solutions set a new path to add value with digital capabilities and offers. The solution automated the Asset's choke model using python codes, compiling results in an interactive dashboard with the most frequent —usually daily— updated production potential. The dashboard grouping and analytics allows quick visualization of opportunities, (i.e. workover candidates such as matrix stimulations, hydraulic fractures and reperforation jobs). The impact included rising awarness of capacity constraints along production system, prioritization based on feasible execution; and better work-life balance for team members; with the corresponding monetary surplus.
- Asia > Middle East (0.47)
- North America (0.30)
- Europe (0.29)
- South America > Bolivia > Tarija Department > Santa Cruz Basin > Caipipendi Block > Margarita Field (0.99)
- Europe > United Kingdom > North Sea > Southern North Sea > Southern Gas Basin > Silver Pit Basin > Block 49/30c > Davy Fields > Brown Field > Rotliegend Formation (0.99)
Overcoming the Operational Challenges of the Amazon Basin and Setting a New Performance Benchmark Using Monobore Wells: A Case Study in Onshore Brazil
Fernandes, G. (Eneva S.A) | Quinones, H. (Eneva S.A) | Carvalho, J. (Eneva S.A) | Harada, L. (Eneva S.A) | Medeiros, T. (Eneva S.A) | Sena, H. (Eneva S.A)
Abstract The success of the first wells campaign in the Azulão Field, North Brazil, was significantly influenced by leveraging the technical and economic advantages of slim monobore wells, a well design methodology that has been successfully utilized for gas production in onshore Brazil. Based on the learnings from the first campaign, the Operator designed an optimization plan to establish a new benchmark for well operations performance and justify further activity expansion in the area. The plan was grounded on an aggressive performance strategy for both the top and production hole sections, using new tech PDC bits, robust mud motors and well trajectory refinements to maximize rate of penetration (ROP). The critical operational risks were confined to the intermediate hole section, namely: severe to total mud losses through hard, naturally fractured diabase rocks and difficult downhole dynamics (shocks and vibrations). And to mitigate their impact, each well location was built with a continuous water supply to allow drilling without interruptions, and the BHA strategy was adjusted to reduce the likelihood of downhole tool failures. From a drilling standpoint, the 12 ¼-in top hole ROP improved by 165%, by using a PDC bit with optimized cutting geometry and a "kick off early and stay slightly above plan" approach for the directional work. Likewise, the 6 1/8-in production hole ROP improved by 70%, by switching to a 5-bladed, 13 mm cutter PDC bit, using a 5-in high differential pressure mud motor and a "zero" sliding approach with the wellbore precisely placed to anticipate the expected formational tendencies down to the geological target. During the last 3 wells, a total of 4 rig days were saved due to the aggregate effect of flat time optimizations. By way of example, a semi-compact wellhead system, which was specifically designed for the slim monobore well design, brought average time savings of +- 10 hours per well. Overall, when compared to the first campaign, the meterage rate from spud to total depth improved by 95%. This, in turn, translated into a 43% metric cost reduction. Similar results were also obtained across 3 wells in a newly discovered area, with a 50% improvement on the meterage rate from spud to total depth, thus contributing towards a 33% metric cost reduction. Capital discipline, synergies and operational efficiencies will be the keystones for success during the current cycle of activity growth in the Brazilian O&G onshore market. This recipe turns particularly critical for remote, logistically and operationally complex environments. Through this paper, the Operator aims to demonstrate the performance evolution and value of slim monobore wells, as one of the best methods to monetize gas production in the Amazon Basin.
- South America > Brazil (1.00)
- South America > Ecuador > Orellana Province (0.61)
- Asia > Middle East > Qatar > Arabian Gulf (0.24)
- Geology > Rock Type (0.93)
- Geology > Geological Subdiscipline > Stratigraphy (0.46)
- South America > Ecuador > Orellana > Amazon Basin (0.99)
- South America > Brazil > Maranhão > Parnaiba Basin (0.99)
- South America > Brazil > Amazonas > Solimoes Basin > Concession BA-3 > Azulão Field (0.99)
- Well Drilling > Well Planning (1.00)
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drilling Operations (1.00)
- (4 more...)
A Novel Workflow to Design Cementing Fluids for Loss Mitigation
Jandhyala, Siva Rama Krishna (Halliburton Energy Services Inc., Houston, Texas, USA) | Yerubandi, Krishna (Halliburton Energy Services Inc., Houston, Texas, USA) | Jimenez, Walmy Cuello (Halliburton Energy Services Inc., Houston, Texas, USA)
Abstract Lost circulation remedial techniques will be effective when they are tailored for the specific challenge. Examples of factors that govern the remedial technique are the type of losses (induced vs. natural fractures, permeable formations, etc.), characteristic size of loss zone, difference between equivalent circulation density and pore pressure gradient, etc. Typically, localized workflows are designed based on experience from wells where these factors are within certain limits. These workflows are limited to the new wells where these factors are within the same limits. Additionally, these workflows usually involve the selection of certain type/size of lost circulation materials (LCMs) with less emphasis on tuning fluid density, rheology, and pump rates. A comprehensive approach, one that caters to a wide range of loss scenarios and allows tuning all engineering parameters available for tailoring the unique solution is needed. The work method discussed herein is built using the principles of mass and momentum conservation. These hydraulic calculations also account for rheology changes due to temperature. The domain of analysis is both the wellbore and the loss zone. Thus, any changes in the wellbore will impact the loss rate and vice-versa. To such a two-way coupled system, a cake buildup model is added in the loss zone to describe the role of filter cake resistance on loss rate. Thus, the proposed method is the most comprehensive approach available to model losses based on wellbore pressures, temperatures and plugging of the loss zone. Such a method allows for greater design flexibility to the engineer in tailoring wellbore fluids during drilling or cement operations. The proposed method is used to understand the sensitivity of the loss zone size to the loss type, loss rate and the depth at which losses occur. This helps engineers highlight the critical information needed from job location to tailor the remedial treatment. The effect of loss zone size on the efficacy of an LCM is demonstrated by evaluating the performance of LCMs of different size and shape. This analysis is useful in tailoring blends made up of different LCMs. Moreover, this work method is used to also compare the impact of rheology and density modification vs. LCMs addition on loss control. This provides greater flexibility in tailoring different aspects of wellbore fluids and placement characteristics. The understanding gained from the above analysis is used in predicting the loss control performance across multiple jobs. These jobs varied in loss rate and loss type. The proposed methodology presented herein revealed an optimum match with actual field observation for all the evaluated jobs. For an example job, the model was able to predict the observed surface pressure. All this analysis further demonstrates the capability of the work method in combating losses by tailoring different aspects of a cement job.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (23 more...)