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The identification of a bed's lithology is fundamental to all reservoir characterization because the physical and chemical properties of the rock that holds hydrocarbons and/or water affect the response of every tool used to measure formation properties. Understanding reservoir lithology is the foundation from which all other petrophysical calculations are made. To make accurate petrophysical calculations of porosity, water saturation (Sw), and permeability, the various lithologies of the reservoir interval must be identified and their implications understood. Lithology means "the composition or type of rock such as sandstone or limestone." Lithology focuses on grains, while rock type focuses on pores. The list of rock types contains more than 250 classifications. Another term used in the literature is the Greek equivalent "petrofacies."
This chapter discusses the determination of lithology, net pay, porosity, water saturation, and permeability from wellbore core and log data. The chapter deals with "Development Petrophysics" and emphasizes the integration of core data with log data; the adjustment of core data, when required, to reservoir conditions; and the calibration and regression line-fitting of log data to core data. The goal of the calculations is to use all available data, calibrated to the best standard, to arrive at the most accurate quantitative values of the petrophysical parameters (i.e., lithology, net pay, porosity, water saturation, and permeability). Log analysis, cased-hole formation evaluation, and production logging are not covered here. The following topics are covered in this chapter: petrophysical data sources and databases, lithology determination, net-pay (or pay/nonpay) determination, porosity determination, fluid-contacts identification, water-saturation determination, permeability ...
This article presents brief summaries of detailed petrophysical evaluations of several fields that have been described in the SPE and Soc. of Professional Well Log Analysts (SPWLA) technical literature. These case studies cover some of the complications that occur when making net-pay, porosity, and water saturation (Sw) calculations. Prudhoe Bay is the largest oil and gas field in North America with more than 20 billion bbl of original oil in place (OOIP) and an overlying 30 Tscf gas cap. In the early 1980s, the unit operating agreement required that a final equity determination be undertaken. In the course of this determination, an extensive field coring program was conducted, which resulted in more than 25 oil-based mud (OBM) cores being cut in all areas of the field and some conventional water-based mud (WBM) and bland-mud cores in other wells.
This chapter concerns gas injection into oil reservoirs to increase oil recovery by immiscible displacement. The use of gas, either of a designed composition or at high-enough pressure, to result in the miscible displacement of oil is not discussed here; for a discussion of that topic, see the chapter on miscible flooding in this section of the Handbook. A variety of gases can and have been used for immiscible gas displacement, with lean hydrocarbon gas used for most applications to date. Historically, immiscible gas injection was first used for reservoir pressure maintenance. The first such projects were initiated in the 1930s and used lean hydrocarbon gas (e.g., Oklahoma City field and Cunningham pool in the United States and Bahrain field in Bahrain). Over the decades, a considerable number of immiscible gas injection projects have been undertaken, some with excellent results and others with poor performance. Reasons for this range of performance are discussed in this chapter. At the end of this chapter, a variety of case studies are presented that briefly describe several of the successful immiscible gas injection projects. Gas injection projects are undertaken when and where there is a readily available supply of gas. This gas supply typically comes from produced solution gas or gas-cap gas, gas produced from a deeper gas-filled reservoir, or gas from a relatively close gas field. The primary physical mechanisms that occur as a result of gas injection are (1) partial or complete maintenance of reservoir pressure, (2) displacement of oil by gas both horizontally and vertically, (3) vaporization of the liquid hydrocarbon components from the oil column and possibly from the gas cap if retrograde condensation has occurred or if the original gas cap contains a relict oil saturation, and (4) swelling of the oil if the oil at original reservoir conditions was very undersaturated with gas. Gas injection is particularly effective in high-relief reservoirs where the process is called "gravity drainage" because the vertical/gravity aspects increase the efficiency of the process and enhance recovery of updip oil residing above the uppermost oil-zone perforations. The decision to apply immiscible gas injection is based on a combination of technical and economic factors. Deferral of gas sales is a significant economic deterrent for many potential gas injection projects if an outlet for immediate gas sales is available.
Techniques described in this page are classic methods for describing immiscible displacement assuming equilibrium between injected gas and displaced oil phases while accounting for differing physical characteristics of the fluids, the effects of reservoir heterogeneities, and injection/production well configurations. Included are modifications to typical displacement equations, evaluating sweep efficiency, and calculating performance. In simple calculations, the reservoir is treated in terms of average properties for volume of rock, and production performance is described on the basis of an average well. Black-oil-type reservoir simulation models use essentially these same techniques but, by means of 1D, 2D, or 3D cell arrays, account for areal and vertical variations in rock and fluid properties, well-to-well gravity effects, and individual well characteristics. More complex compositional models account for nonequilibrium conditions between injected and displaced fluids and can be used to describe individual well streams in terms of the compositions of the produced fluids.
Cedillo, Gerardo (BP Exploration Alaska) | Zett, Adrian (BP Exploration Alaska) | Han, Xiaogang (BP Exploration Alaska) | Elghonimy, Rana (BP Exploration Alaska) | Raeesi, Behrooz (BP Exploration Alaska) | Itter, David (BP Exploration Alaska) | Hecker, Dodie (BP Exploration Alaska) | Landi, Nancy (BP Exploration Alaska)
Swellable packer evaluation has become a critical component of Greater Prudhoe Bay (GPB) well design, surveillance and diagnostic strategy. Currently in the field there are several wells constructed with cementless completions with over 500 water or oil swellable packers across three different reservoirs. Several early gas or water breakouts have been documented since these types of completions have been deployed and the need for an accurate diagnostic technique to distinguish between a reservoir phenomenon or a completion failure motivated this work. The borax evaluation technique historically has been successfully used in oil fields on the North Slope of Alaska to detect fluid channeling mainly in horizontal cemented and perforated wells. This technique however, was never used to evaluate swellable packers in horizontal cementless completions. Even when the same multi-detector pulsed neutron (MDPN) instrument could be used in real time or memory conveyance to evaluate either one, there are fundamental differences in how these cementless completions are designed and evaluated compared to the cemented and perforated ones. Ignoring those differences could lead to the wrong nuclear attribute selection and incorrect interpretations, diagnostics and remediation strategies. The objective of this paper is to describe the nuclear modelling performed, the wellsite procedures used, the interpretation workflow, and the results of evaluations of these completions.
Various recovery mechanisms such as gravity drainage, water flooding and miscible injection have historically been implemented in the Prudhoe Bay Field, Alaska, which have changed the initial fluid distribution over most of the reservoir interval. In these areas of altered fluid saturations, the importance of accurately quantifying multicomponent fluid saturations is critical in planning well work activity and maximizing production and recovery.
Early in field life, the quantitative approach to determining fluid saturations relied on vintage chemical neutron logging tools, which were later replaced by pulsed neutron technology. The increased complexity in fluids redistribution (more than three fluids) required a different approach for quantitative evaluations. The solution came through development of Multidetector Pulsed Neutron (MDPN) technologies, by broadening the range and sensitivity of nuclear attributes used to discriminate various fluids present in the reservoir.
Recently, the MDPN technology diversified with more instruments being developed and field tested. While all share the same physics principle, the responses can vary due to instrumentation design, characterization and nuclear attributes extraction in the field.
We field tested and evaluated the MDPN technologies of three developers. The selection of a fit for purpose MDPN technology is a multi-variable decision that takes into account the tool accuracy, repeatability, and sensitivity of various nuclear attributes for a specific recovery mechanism. In the current low oil price environment, it is very important to understand, discretize, and quantify each of these attributes in order to incorporate them in a value of information exercise, and then select the best value option that accurately characterizes the fluid saturation and distribution in the reservoir.
This paper will describe in detail the results of field trials of three MDPN instruments in the Prudhoe Bay Field, on the North Slope of Alaska. A comprehensive comparison of raw data (including statistics and coherence analysis) and multi-vendor interpretations will be discussed along with inhouse results benchmarked to detail rock and fluid description, as well as production history and well work results.
As exploratory work in Alaska moves beyond the known petroleum basins, new remote areas will be explored, where little sub surface data is available. This paper examines the overburden of Alaska, and develops a general relationship for determining overburden pressures based on the general geographic location in this region.
To develop such relationships, well logs available to the Public are used. To characterize the overburden on a large scale, three major sedimentary basins of the Alaska, the North Slope, Nenana Basin, and Cook Inlet Basin, are studied. Overburden is estimated by integrating density of the deposits, from using density log data, and using MATLAB to filter false readings. From this data, a regionalized relationship is developed for pressure vs depth, based on geographical location.
The collision of the Pacific Plate and North American Plate has resulted in thrust tectonics, associated with shortening and thickening of the crust at southern part of the Alaska Microplate. The studied basins are located along different locations in this deformation zone and evident with different lithological patterns across a north-south direction. Depending on tectonics and diagenesis of sediments, rocks undergo different compaction processes which make overburden various across this region. As a result of plate tectonics and variation in depositional environments, an increasing trend is observed across the entire Alaska region. Such trend can be used in further exploration work in this region to approximate overburden stress at any location in the state.
The natural decline in oil production in Alaskan reservoirs is challenging producers to find methods to extend production. The current stage of reservoir development has reached the point where consideration of enhanced oil recovery methods is appropriate. Such methods could include CO2, chemical, microbial or thermal recovery. However, these methods require significant capital and/or operational investment. This paper evaluates the application of wettability alteration for Alaskan reservoirs by changing injection water chemistry also known as advanced water flooding. We use empirically-based screening and scoping methodologies to evaluate the suitability, cost and benefits of advanced water flooding for Alaskan reservoirs using public domain data.
First, laboratory and field examples of successes and failures are considered. Using this basis, a theory is developed that directly links water chemistry and reservoir wettability. The theory also illuminates the key characteristics of the reservoir that control wettability. We use empirically-based screening and scoping methodologies to evaluate the suitability, cost and benefits of advanced water flooding for Alaskan reservoirs with sufficient public domain data. The screening tool is built on empirical data from laboratory and field tests that identify the critical factors contributing to incremental production. The scoping tool uses a modified Kinder Morgan approach (dimensionless recovery curve) to evaluate the economic case for each reservoir.
The first field-scale tests of this technique were conducted by BP in the Endicott reservoir on the North Slope and produced good results by lowering the salinity of injection water. Those tests showed that alteration to injection water chemistry can increase recovery significantly. These results have been duplicated in laboratory and field tests in other locations. The tests were conducted without an understanding of the fundamental mechanisms nor optimization of the injected water chemistry, and thus represent minimum recovery. We find the increased recovery is profitable for several fields depending on assumptions about water sources, water treatment costs and rates of injection.
The successful approach to advanced waterflooding requires several key steps: screening the formation to evaluate the applicability of the technique, simple laboratory tests to determine the optimal water chemistry and quantify the increased recovery, economic evaluations to estimate costs and benefits, and finally, comprehensive geochemical models to design the wettability-modifying fluids. The technique has several advantages compared to current methodologies for wettability alteration including substantially lower costs, no environmental impacts and ease of application.
Thrasher, David (BP Exploration) | Nottingham, Derek (BP Exploration (Alaska) Inc.) | Stechauner, Bernhard (BP Exploration (Alaska) Inc.) | Ohms, Danielle (BP Exploration (Alaska) Inc.) | Stechauner, Gerda (BP Exploration (Alaska) Inc.) | Singh, Praveen K. (BP America Inc.) | Angarita, Monica Lara (BP Exploration)
Waterflood conformance control due to reservoir heterogeneity is a common challenge to many oilfield developments. This paper describes the application at-scale of a thermally-activated polymer particle system (TAP) for improving waterflood sweep efficiency in the Prudhoe Bay field, Alaska. Since 2004, the technology has been successfully deployed 91 times in Prudhoe Bay Unit on the North Slope of Alaska as part of an approved Enhanced Oil Recovery (EOR) program. A total of 1.6 million gallons of chemical polymer particles have been injected into approximately half of the available waterflood patterns.
Once the polymer particles activate deep in the reservoir, they provide resistance to water flow in the thief (swept) zones. The treatment design workflow applies a thermal model which accounts for the impact of the temperature distribution in the reservoir on activation of the polymer particles. Challenges associated with performance evaluation of the treatment program in a normal operational setting (as opposed to field trial) have been addressed, particularly in relation to interferences to interpretation resulting from the ongoing application of miscible gas EOR in the waterflood areas.
Of the 44 treatments deployed between 2008 and 2012, 22 were sufficiently mature to have performance data which was not adversely impacted by interferences from well work, changes to operating conditions, or miscible gas breakthrough. So far, only one of the 22 patterns has not indicated an incremental oil response, while in two patterns the response had started too recently to be able to extrapolate the overall response magnitude. The analysis showed overall positive responses from the treatments that are competitive with other well work on cost/bbl and project economics. Results from this study provide insights on key controls on waterflood sweep improvements, and inform future candidate selection and optimization of treatment designs.
The production performance analysis was corroborated by wellhead injectivity, repeat pressure fall-off tests, and reservoir modeling. This paper documents a good case history of waterflood sweep improvement.