For a low-pressure well with solids and/or heavy oil at a depth of less than approximately 6,000 ft and if the well temperature is not high (75 to 150 F typical, approximately 250 F or higher maximum), a PCP should be evaluated. Even if problems do not exist, a PCP might be a good choice to take advantage of its good power efficiency. If the application is offshore, or if pulling the well is very expensive and the well is most likely deviated, ESPCP should be considered so that rod/tubing wear is not excessive. There is an ESPCP option that allows wire lining out a failed pump from the well while leaving the seal section, gearbox, motor, and cable installed for continued use.
Venezuela possesses a world-class, hydrocarbon source rock from one of the most prolific places for oil accumulation in the world. This source rock, the La Luna Formation, (Cretaceous in age) is located in eastern Venezuela's Maracaibo Basin. Local variations in depositional and diagenetic conditions have manifestly affected the preservation and dilution of organic matter to some degree, generating small-scale variability in the depositional environments, and thus creating a higher-quality source rock within the depositional sequence that can be more prospective than others. To understand the variability of the depositional conditions, variations in organic matter source, thermal maturity, depositional environments and the use of organic/inorganic geochemical parameters were crucial in this study. This combined source rock evaluation composed of geological and geochemical parameters indicated an excellent potential as an unconventional reservoir for oil and gas in the study area. Geochemical analysis (Pristane, phytane (Pr/Ph), distributions of regular steranes, hopanes, monoaromatic steroid hydrocarbons (MAS) and tentative identification of gammacerane) confirmed the excellent quality of the organo-facies with higher productivity and preservation. Thermal maturity parameters indicate that most of the studied cores are within the oil window. Liquid hydrocarbons in the study area occur in the northwest and southwest areas, and condensates and dry/wet gases occur in the northeast. The lithofacies association, the sequence-stratigraphic framework, relative hydrocarbon potential (RHP), and biomarker analysis identified the depositional environment as an epicontinental sea developed in a shallow marine, upper shelf euxinic environment represented by a series of third order sequences of Highstand and Transgressive System Tracts overlying the erosional top of the underlying Cogollo Group. These stark differences show the tremendous value that biomarkers provide in the exploration of prospective source rocks. Not only do they help to identify paleoenvironmental changes and redox conditions, but they also depict the best organo-facies and accurate maturity parameters of the rock.
Objectives/Scope: Understanding that capillary forces will act to limit petroleum fluid saturations in water-wet fine-grained rocks, including organic rich source rocks, dates back at least to Hubbert (1953). Likewise, Philippi (1965) noted relationships identifying sorption in/on organic matter as a significant storage mechanism in organic-rich rocks. Contrast these early insights with current unconventional reservoir evaluation, where we observe a disconnect between in situ (core exhumed to surface) measured total water saturations vs. the produced cumulative water volumes from a given stimulated rock volume. Water-free production in gas shales, from gas-wet organic matrix pores, created an early impression that unconventional plays don't produce water. So, in more liquid-rich plays, water cuts were initially under-appreciated: e.g. >80% in the Wolfcamp (stock-tank basis). If measured Sw is so low (core-based calibration), where is the water coming from; or is there an alternative method to more accurately relate in situ to produced water and petroleum production?
Methods/Procedures/Process: Adapting organic sorption models from the 80's, we can split total hydrocarbon volatiles into sorbed and, by difference, non-sorbed (fluid phase) yields. Converting to volumes and adding back dissolved gas using a formation volume factor (FVF) we can estimate the bulk volume fluid phase. This new approach then yields observations regarding remaining water-filled pore volume versus sorbed and non-sorbed hydrocarbon volume explaining the high water cuts in the Permian Basin stratigraphy; and additionally may indicate sweet spots in pore systems in different parts of the rock compared to alternatively derived saturations.
Results/Observations/Conclusions: The final piece of the puzzle comes from basin modeling of petroleum charging in the 90's. Some scientists applied conventional reservoir relative permeability to fine-grained rocks, but new research predicted that progressively finer grained rocks with higher irreducible water should be able to flow oil at progressively higher Sw: at 100nD, both oil and water should flow at Sw > 80%. Lower petroleum phase saturations and adjusted relative permeability curves may better explain observed production behaviors and profoundly alter our view of recovery factor and stimulated rock volume.
Applications/Significance/Novelty: The method offers an alternate and independent method to Dean-Stark-based core / SWC saturation analysis and its pitfalls. Saturation patterns after removal of immobile sorbed oil are different to those derived using the Dean-Stark based method, implying sweet spots / landing zones can be further optimized even in maturing shale plays. Lower oil-in-place – representing only the potentially mobile fluid phase petroleum – means that fracture stimulation has a higher recovery factor than previously thought, with profound effects on the infill volumes / opportunities for future field developments and therefore ultimately for US – and global – oil supply projections.
Interdisciplinary Components: Cross-over technology from organic geochemistry to petrophysics to reservoir engineering.
This study presents a methodology for a 3D geomechanical model on unconventional shale play in Colombia. Pre-stack time migration (PSTM) was used to populate the model and Vertical Transverse Isotropy (VTI) was applied to calculate the anisotropic mechanical properties of the shale. A drilling campaign has encountered several exceptional shale plays in Colombia in the past few years. Extensive tri-axial and pyrolysis measurements have been included in the study to calibrate the mechanical properties and organic composition derived from well logging. Geomechanical and geochemical characterization of these shales have been used to provide the required information for designing optimal well trajectories and understanding reservoir and completion qualities. Using seismic inversion software package, inversion of the seismic from pre-stack time migration was conducted to deliver a 3D volume of P-wave impedance and S-wave impedance and bulk density to have lateral and vertical spatial coverage. The pore pressure, litho-facies, mechanical properties, and Total Organic Carbon (TOC) in specific areas of the reservoir were determined using electrical and image logs, core samples, drill cuttings, and drilling reports from two vertical wells in the field. The results were used in recommending specific development scenarios in the shale play.
3D Geomechanical model is essential for unconventional shale reservoir field development, well integrity, horizontal well placement and in-fill child well drilling. In this study, an investigation is conducted to develop a 3D geomechanical model for a shale play in Colombia. Moreover, a 1D geomechanical model was also included to determine the mud weight window with three different rock failure criteria, mechanical rock properties considering VTI rock isotropy, TOC and kerogen type. Utilizing the developed 1D and 3D geomechanical models, wellbore instability issues have been predicted to reduce Non-Productive Time (NPT) events that can be experienced during drilling and completion of the wells in the studied unconventional reservoir. The effects of the strike slip and reverse stress regimes for drilling and hydraulic fracturing during development of the field at depths of more than 10,000 ft. (TVD) has also been integrated in the analysis.
Many gas reservoirs at the appraisal stage exhibit evidence of persistent gas saturations below free water levels (FWL's). The amounts of gas contained here may, under some situations, be a sizable fraction of the gas cap volumes. Many engineers appear poorly equipped to include, and model, paleo gas in simulation models. This often results in paleo gas being simply ignored when development plans are being considered. This is unfortunate because paleo gas upon pressure depletion can expand, displacing brine towards well completions. This means that while some additional gas production may occur from the paleo zone, the risk of water production may be significantly underestimated if paleo gas is simply omitted. This work discusses the evidence for paleo gas and shows that it may be described and incorporated in simple simulation models provided the user avoids some common misconceptions. It is demonstrated that under depletion conditions, paleo gas can be entirely visible to material balance pressure responses, while at the same time increasing the risk of produced water volumes. For higher pressure paleo gas reservoirs the common P on Z diagnostic plots can also provide early trends that are frequently misinterpreted. This work quantifies the curvature that can result in such systems, and shows that simulation models inherently predict the expected curvature in P on Z. The approach taken here is by design simplistic and is applicable to scoping evaluations where the paleo gas volumes could be a significant volumetric uncertainty. Where possible, we indicate where additional, or more rigorous, descriptions can be applied.
The resistivity index (RI) of Fontainebleau and Bentheimer sandstones was investigated at ambient and reservoir pressures down to low water saturations. The RI measurements show that both sandstones display Archie behavior at elevated pressure. This paper presents experimental and field-case studies with a sandstone-acidizing treatment designed to retard the hydrofluoric acid reaction rate and enable single-stage treatment. This paper describes a matrix-acidizing campaign executed successfully in the Gulf of Cambay on the west coast of India.
A high-carbon-dioxide (CO2) carbonate gas field offshore Sarawak, Malaysia, is scheduled for development. Reservoirs in this region have an average clay content of 8%; more than 50% of this clay content is migratory illite, and 15% is migratory kaolinite. The complete paper presents a numerical work flow to simulate the effect of flow-induced fines migration on production decline over time in deepwater reservoirs. Production and drawdown data from 10 subsea deepwater fractured wells have been modeled with an analytical model for unsteady-state flow with fines migration.
This paper covers the staged field-development methodology, including analysis and evaluation of various development concepts, that enabled the company to optimize both completion design and artificial-lift selection, reducing downtime and lowering operating costs by nearly 50%. Completion engineers feel pressure to maximize production per acre and minimize the downsides of fracturing in tight spaces. Terry Palisch, talks about promoting knowledge sharing as part of JPT’s tech director report. Seismic stimulation, achievable with the implementation of a single tool, requires significantly lower investments than gas, thermal, and chemical injection methods, with minimal environmental impact. This paper describes an experimental study with a new propellant and aims to understand the pattern of fracture creation with these propellants.
This paper uses a simulation model to evaluate and compare the thermal efficiency of five different completion design cases during the SAGD circulation phase in the Lloydminster formation in the Lindbergh area in Alberta, Canada. The cost reduction per barrel of oil produced and the extension of sustainable production life by optimization have been two major areas of focus, but the investments in new technologies and recovery-improvement research have not received sufficient attention during the downturn. This paper covers the staged field-development methodology, including analysis and evaluation of various development concepts, that enabled the company to optimize both completion design and artificial-lift selection, reducing downtime and lowering operating costs by nearly 50%. This paper shares experience gained in the Ashalchinskoye heavy-oil field with a two-wellhead SAGD modification. As a result of a pilot for this technology in Russia, the accumulated production of three pairs of these wells is greater than 200,000 tons.
Formation damage: Do we always need to have a high focus on its prevention, or do occasions exist when it really does not matter? This paper describes a coreflooding program performed with sandpacks at different permeabilities, water qualities, and injection conditions. Because of inherent complexities, understanding the characteristics of perforations in downhole environments is a significant challenge. Perforation-flow laboratories have been used to provide insight into cleanup and productivity mechanisms around perforation tunnels. A high-carbon-dioxide (CO2) carbonate gas field offshore Sarawak, Malaysia, is scheduled for development.