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Abstract Thermal maturity is an important parameter for commercial gas production from gas shale reservoirs if the shale has considerable organic content. There is a common idea that gas shale formations with higher potential for gas production are at higher thermal maturity status. Therefore estimating this parameter is very important for gas shale evaluation. The present study proposes an index for determining thermal maturity of the gas shale layers using the conventional well log data. To approach this objective, different conventional well logs were studied and neutron porosity, density and volumetric photoelectric adsorption were selected as the most proper inputs for defining a log derived maturity index (LMI). LMI considers the effects of thermal maturity on the mentioned well logs and applies these effects for modelling thermal maturity changes. The proposed methodology has been applied to estimate thermal maturity for Kockatea Shale and Carynginia Formation of the Northern Perth Basin, Western Australia. A total number of ninety eight geochemical data points from seven wells were used for calibrating with well log data. Although there are some limitations for LMI but generally it can give a good in-situ estimation of thermal maturity.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Oceania > Australia > Western Australia > Perth Basin > Northern Perth Basin (0.99)
- Oceania > Australia > Western Australia > Perth Basin > Kockatea Shale Formation (0.99)
- Oceania > Australia > Western Australia > Perth Basin > Carynginia Shale Formation (0.99)
- (13 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Geochemical characterization (1.00)
Design, Qualification, and Installation of Openhole Gravel Packs: Mari B Field, Offshore Israel
Healy, John (Noble Energy) | Sanford, Jack (Noble Energy) | Reeves, Donald (Noble Energy) | Dufrene, Kerby (formerly with Schlumberger) | Luyster, Mark (M-I SWACO) | Offenbacher, Matt (M-I SWACO) | Ezeigbo, Eze (M-I SWACO)
Abstract A case history from Offshore Israel is presented that describes the successful delivery of two ultra high-rate gas wells (>200 MMscf/D) completed in a depleted gas reservoir with 9⅝-in. production tubing and an openhole gravel pack (OHGP). Maximizing gas off-take rates from a volumetric drive gas reservoir that possesses high flow capacity (kh) requires large internal diameter (ID) tubing coupled with efficient sand face completions. When sand control is required, the OHGP offers the most efficient as well as the most reliable, long-term track record of performance. A global study of wells completed with 9⅝-in. production tubing ("big bore") determined that this design concept was feasible and deliverable in a short time frame while still maintaining engineering rigor. The paper will highlight key accomplishments within various phases of a completion delivery process with particular emphasis on the sand control design, testing and execution. The completions were installed with minimal issues (NPT ≈ 9%) and have produced without incident. The two wells, Mari-B #9 and #10, achieved a peak gas rate of 223 and 246 MMscf/D, respectively.
- Asia > Middle East > Israel (0.70)
- North America > United States > California (0.46)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Exmouth Basin > WA-32-L > Stybarrow Field > Macedon Formation (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Exmouth Basin > WA-255-P > Stybarrow Field > Macedon Formation (0.99)
- North America > Trinidad and Tobago > Trinidad > North Atlantic Ocean > Columbus Basin > South East Galeota Block > Cannonball Field (0.99)
- (6 more...)
Offshore ESP Selection Criteria: An Industry Study
Romer, Michael C. (ExxonMobil Production Company) | Johnson, Mark E. (ExxonMobil Production Company) | Underwood, Pat C. (ExxonMobil Production Company) | Albers, Amanda L. (ExxonMobil Production Company) | Bacon, Russ M. (R.M. Bacon Engineering Ltd)
Abstract Most offshore wells that require artificial lift are gas lifted, as gas typically is readily available and compared to other lift systems, gas lifting is relatively inexpensive and low maintenance. However, electric submersible pumps (ESPs) can efficiently and economically increase oil production and reserves recovery under the appropriate operating conditions. This may translate to a lower abandonment pressure in the long term—possibly reducing the total number of wells required to deplete an asset. Since few ESPs currently are installed in offshore wells, an ESP screening "Rules of Thumb" was created as a simple guide for prioritizing offshore ESP candidates. The selection criteria focus on feasibility of installation, operability conditions and operating practices to maximize run life, and economic considerations. ExxonMobil† and industry experience from North America, South America, West Africa, Asia, Australia, the Middle East, and the North Sea provided the basis for the study.
- Asia > Middle East > Qatar (0.68)
- North America > United States > Texas (0.49)
- Europe > United Kingdom > North Sea (0.48)
- North America > United States > California (0.46)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Block BM-C-7 > Peregrino Heavy Field (0.99)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Block BM-C-47 > Peregrino Heavy Field (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Carnarvon Basin > Dampier Basin > WA-191-P > Block WA-27-L > Mutineer-Exeter Field > Exeter Field > Angel Formation (0.99)
- (10 more...)
Recent Progress of High-Pressure Air Injection (HPAI) Process in Light Oil Reservoir: Laboratory Investigation and Field Application
Jia, Hu (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University, China) | Yuan, Cheng-Dong (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University, China) | Zhang, Yu-Chuan (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University, China) | Peng, Huan (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University, China) | Zhong, Dong (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University, China) | Zhao, Jin-Zhou (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University, China)
Abstract High-Pressure Air Injection (HPAI) in light oil reservoirs has been proven to be a valuable IOR (Improved Oil Recovery) process and caused more attention worldwide. In this paper, we give an overview of the recent progress of HPAI technique, based on a review of some representative HPAI projects including completed and ongoing projects. Some most important aspects for HPAI field application are discussed in depth, including reservoir screening criterion, recognition of recovery mechanism, laboratory study, numerical simulation, gas breakthrough control, tubing corrosion consideration and safety monitoring. With the successful HPAI application in Zhong Yuan Oil Field in China, it is estimated that foam or polymer gel assisted air injection should continue to grow in the next decade as a derived technology of HPAI for application in high-temperature high-heterogeneity reservoirs. The purpose of this paper is to investigate the ranges of some key parameters, new understanding based on laboratory test and successful field application, thus to provide lessons learnt and best practices for the guideline to achieve high-performance HPAI project.
- North America > United States > Texas (1.00)
- Europe (1.00)
- Oceania > Australia > Western Australia (0.93)
- (2 more...)
- Research Report (0.46)
- Overview (0.34)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.73)
- Geology > Mineral > Silicate > Phyllosilicate (0.49)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.46)
- Oceania > Australia > Western Australia > Carnarvon Basin (0.99)
- Oceania > Australia > South Australia > Cooper Eromanga Basin (0.99)
- Oceania > Australia > Queensland > Surat-Bowen Basin (0.99)
- (34 more...)
Abstract The plans for many of the upcoming deepwater projects involve the use of highpower Electrical Submersible Pump (ESP) Systems for Artificial Lift. However, the perception in the industry is that the average run-life currentlyachievable with such high power ESP Systems is much shorter than what would bedictated by robust project economics, given that intervention costs in theseapplications can be very high, in the US$50MM - 75MM range. Therefore, theconsensus among operators is that there is a need to try and improve thereliability of these systems. In response to this industry need, DeepStar® recently commissioned a gap studytowards identifying the barriers that may be preventing ESP Systems fromachieving the desired reliability as well as the additional R&D effort thatmay be required for the industry to close the existing gap. DeeepStar® providesa forum for deepwater technology development, while leveraging the financialand technical resources of the industry (). This paper presents a summary of the results of this study, including:the Mean Time To Failure (MTTF) that people believe is currently achievable (i.e.with current technology); the biggest differences about these applications, which introduce additional uncertainty to the ability of the system to performreliably; the main sources of uncertainty regarding each of the major ESPSystem component's reliability; and the tentative plan that was outlined aspart of the project, to address the gaps that were identified. The Gap Analysis was based on phone interviews conducted with recognizedindustry experts, on discussions that took place with members of a TechnicalCommittee (TC) that was put in place for the project, and on a broader industrysurvey conducted through the internet. The proposed go-forward plan consists oftwo follow-up projects: one focused on improved system design and operationalpractices, including system monitoring (or surveillance) and control; and onefocused on validating the design of key components of concern, for thespecifics of these applications, through laboratory testing. The proposednear-future R&D effort has the support of major operators, but still needsto be fine-tuned, with input from the industry, before the actual work canproceed with buy-in and financial support from all of the partiesinvolved. Introduction The Oil and Gas industry continues to move towards more challengingexploitation environments offshore: deeper water (over 10,000 ft), longertie-backs, deeper reservoirs (up to 20,000 ft below the mud line), and/or withhigher viscosity oil. The plans for many of the major projects currentlyunderway in such offshore environments involve the use of relatively high powerElectrical Submersible Pump (ESP) Systems for Artificial Lift. These include, for instance: Shell's " Parque das Conchas" and Petrobras' " Parque das Baleias" in Brazil's Campos Basin, as well as Shell's Perdido, Petrobras' Cascade andChinook, and a few other projects in deep waters in the US' Gulf of Mexico(GOM) such as Chevron's Big Foot. Operating in these extreme environments will likely require deploying newproduction systems (e.g. with subsea boosting) and/or new generations of ESPequipment. While individual well production rates can exceed 20,000 bpd of oil, understanding of well performance is usually only marginal at the time ofsystem design and installation. Intervention costs in these scenarios can bevery high, sometimes in the US$50MM - 75MM range (per intervention). Productionlosses following an equipment failure can also be quite significant, especiallyfor wells with higher production rates. Therefore, the economic success ofthese projects is closely linked to the ability to minimize the number ofinterventions for equipment repair and maximize production uptime. Thisrequires not only using highly inherently reliable equipment but also havingthe best possible design and operational practices in place, in order to beable to actually realize the whole reliability potential of the equipment. Astated goal by some operators is to have 95% confidence that a 5 year run-lifecan be obtained from the ESP System, despite this very challenging operatingenvironment.
- South America > Brazil (1.00)
- North America > United States > Texas > Harris County > Houston (0.15)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > South America Government > Brazil Government (0.45)
- South America > Brazil > Campos Basin (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Carnarvon Basin > Dampier Basin > WA-191-P > Block WA-27-L > Mutineer-Exeter Field > Exeter Field > Angel Formation (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Beagle Basin > Dampier Basin > WA-191-P > Block WA-27-L > Mutineer-Exeter Field > Exeter Field > Angel Formation (0.99)
- (6 more...)
Abstract The giant Wafra Field is the largest field in the Partition Zone (PZ) between Saudi Arabia and Kuwait. The Cretaceous Wara reservoir represents one of the most prolific producing zones in the PZ. The Wara is a Cretaceous sequence of channel sands (fluvial/tidal) that have locally complex vertical and a stacking patterns. These sands are interpreted to have been deposited in a tidally influenced lower delta plain depositional environment in a low angle ramp setting characterized by low accommodation space. Stratigraphic complexity is high and in general, sandstone bodies are below seismic resolution. The Wafra Wara reservoir is a structural accumulation formed by a low amplitude anticline with 4-way dip closure, with some structural complexity at the reservoir level, consisting of normal faults with small displacements. Although the Wafra Wara clastic reservoir is mature, new "sweet spots" with original formation pressure were drilled recently in the middle of the development area, and there is also still significant remaining oil on the current margins of the field where deeper OWCs have recently been encountered. Increasing water cut and an active aquifer present some challenges to maintaining good oil production in the reservoir, mitigated by production optimization efforts and a rigorous surveillance program. A comprehensive multidisciplinary study was performed to identify new infill well and workover opportunities within the most mature portion of the field to increase production and recovery. The team reviewed all existing data and performed detailed 3D-seismic interpretation to refine stratigraphy and structure, generate production attribute maps and to understand the production history and current state of the reservoir. Production, well-test data, cased-hole logs and analytical techniques were used to identify areas with by-passed oil and to predict initial rates and incremental recovery for infill wells. Deterministic and probabilistic forecasts were generated using field and offset well decline curve analysis. New opportunities were then ranked based on geological and engineering criteria. This paper highlights the challenges and lessons learned from this integrated reservoir management study to define remaining oil and to identify opportunities to increase ultimate recovery.
- Geology > Structural Geology (1.00)
- Geology > Geological Subdiscipline > Stratigraphy (1.00)
- Geology > Sedimentary Geology > Depositional Environment > Continental Environment > Fluvial Environment (0.48)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.36)
- Asia > Middle East > Saudi Arabia > Saudi Arabia - Kuwait Neutral Zone ("Partitioned Zone") > Arabian Basin > Widyan Basin > Wafra Joint Operations Block > Wafra Field (0.99)
- Asia > Middle East > Kuwait > Saudi Arabia - Kuwait Neutral Zone ("Partitioned Zone") > Arabian Basin > Widyan Basin > Wafra Joint Operations Block > Wafra Field (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Wara Formation (0.99)
- (13 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation (1.00)
- (4 more...)
Summary Probabilistic methods for reserves estimation, including uncertainty quantification and probabilistic aggregation, have gained widespread acceptance in the oil and gas industry, since the first comprehensive guidelines were issued by the Society of Petroleum Engineers (SPE) (Swinkels 2001). The probabilistic methods now used in the oil industry, as proposed in these guidelines, are similar to those also used in portfolio theory and risk management by the finance industry. A significant amount can be learned from the extensive experience with probabilistic methods and quantification of risk with measures like value-at-risk (VAR), in financial risk management. Especially, the guidelines issued by the Basel II Accord (Bank for International Settlements 2006) and the discussions since the 2008 financial crisis contain important lessons. In this paper, we examine a fundamental question: "Is the P90 reserves value an appropriate measure for quantifying the reserves’ downside?" For the P90 reserves value to be considered a good measure of the reserves’ downside, it needs to possess a number of basic characteristics involving P90 reserves for each field and the probabilistically aggregated P90 reserves for the portfolio of fields. Analogous to the definition of a coherent risk measure used in the finance industry, we define these characteristics for P90 reserves. The P90 reserves are as good a risk measure as VAR used in the financial industry. However, like VAR, it is not a coherent risk measure. A possible uncertainty scenario, in which one of these necessary characteristics does not hold, is given. An alternative measure of risk for quantifying the reserves’ downside, defined as the average reserves over the confidence interval higher than P90, is presented. This is a coherent risk measure. In this paper, we highlight the appropriateness and limitations of using the P90 reserves estimate as a measure of the reserves’ downside. Understanding of the limitations posed by using the P90 reserves value is vital in management of reserves risk.
- Asia (1.00)
- North America > United States > Texas (0.46)
- Oceania > Australia > Western Australia (0.29)
- (2 more...)
- Energy > Oil & Gas > Upstream (1.00)
- Banking & Finance (1.00)
- Africa > Cameroon > Gulf of Guinea > Rio Del Ray Basin > Etinde Block > IF Field (0.99)
- Oceania > Australia > Western Australia > Western Australia > Timor Sea > Browse Basin (0.89)
- Oceania > Australia > Western Australia > North West Shelf > Timor Sea > Browse Basin (0.89)
- (4 more...)
- Reservoir Description and Dynamics > Reserves Evaluation > Probabilistic methods (1.00)
- Management > Risk Management and Decision-Making (1.00)
- Management > Asset and Portfolio Management > Reserves replacement, booking and auditing (0.89)
- Well Drilling > Drilling Operations > Drilling operation management (0.75)