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Abstract During well planning, drillers and petrophysicists have different principle objectives. The petrophysicist’s aim is to acquire critical well data, but this can lead to increased operational risk. The driller is focused on optimizing the well design, which can result in compromised data quality. In extreme cases, the impact of well design on petrophysical data can lead to erroneous post-well results that impact the entire value-chain assessment and decision making toward field development. In this paper, we present a case study from a syn-rift, Upper Jurassic reservoir in the Norwegian Sea where well design significantly impacted reservoir characterization. Three wells (exploration, appraisal, and geopilot) are compared in order to demonstrate the impact of overbalanced drilling on well data from both logs and core. Implications for reservoir quality assessment, volume estimates, and the errors introduced into both a static geomodel and dynamic reservoir simulation are discussed. This case study highlights the importance of optimizing well design for petrophysical data collection and demonstrates the potential for value creation. Extensive data collection was initially carried out in both exploration and appraisal wells, including full sets of logging while drilling (LWD), wireline logging, fluid sampling, and extensive coring. Both wells were drilled with considerable overbalanced mud weights due to the risk of overpressured reservoirs in the region. The log data was subsequently corrected for significant mud-filtration invasion, with calibration to core measurements guiding the interpretation. Geological and reservoir models were built based on results from the two wells, and development wells were planned accordingly. A thorough investigation of core material raised suspicion that there could also be a significant adverse effect of core properties resulting from overbalanced drilling. The implications were so significant for the reservoir volume that a strategic decision was made to drill a geopilot well close to the initial exploration well, prior to field development drilling. The well was drilled six years after the initial exploration phase with considerably lower overbalance. Extensive well data, including one core, were acquired. The recovered core was crucial in order to compare the reservoir properties for comparable facies between all three wells. The results from the core demonstrate distinctly different rock quality characteristics, especially at the high end of the reservoir quality spectrum. Results of the core study confirmed the initial hypothesis that overbalanced drilling had significantly impacted the properties of the core as well as the well logs. The study concluded that the updated reservoir model properties would significantly increase the in-place volumes compared to the pre-geopilot estimate. This study shows how well design adversely affected petrophysical measurements and how errors in these data compromised geological and reservoir models, leading to a suboptimal field development plan that eroded significant value. This example provides a case study that can be used to improve the well design so that petrophysicists and drillers can both be part of the same value creation result. Future work will include further laboratory investigations on the effects of high overbalanced drilling on core and possible “root causes” for compromised core integrity.
Summary In this paper we present a method for identifying intervals in shale oil reservoirs that contain moveable hydrocarbons with a novel geochemical productivity index (PI), . This index merges three important rock properties that must always be considered for sound shale oil reservoir characterization: vitrinite reflectance (), oil–saturation index (OSI), and free–water porosity (). Integrating this index with other petrophysical properties and geomechanical parameters defines intervals with high moveable oil content. Shale oil is both a source rock and an unconventional reservoir rock. Hence, it is critical to know both its organic–matter (OM) maturity and its oil/water flow capacity. The introduced considered these features simultaneously; maturity was evaluated by discretizing from 0 to 1, depending on whether the rock was immature or not; free oil flow capacity modeled the normalizing between 0 and 1 on the basis of results from the Rock-Eval VI pyrolysis (REP) obtained in the laboratory or by electric logs; and water flow capacity was estimated from , obtained using a nuclear–magnetic–resonance (NMR) log, which was transformed into an index between 0 and 1. Flow oil capacity was defined as the amount of moveable oil that exceeded the sorption capacity of the source rock. Using the is explained with real data from a vertical well that penetrates several stacked shale oil reservoirs. However, the same approach can be used in any other type of wellbore architecture (i.e., deviated, horizontal, geosteered). Initially, a correlation between vertical depth and was developed. This resulted in a continuous OM–maturity curve along the well section. Next, OSI was simulated by using a bin porosity from an NMR log, where was between 33 and 80 milliseconds and was correlated with OSI data from REP. As a result, a good match between the simulated and the real OSI data was achieved. Similar to OSI, was also calculated from the NMR log, but it used a bin porosity when was greater than 80 milliseconds. These three parameters were then transformed to fractional indices, which were combined into a unique index, . When the index was greater than 0.66, there was a good chance that the three conditions mentioned above would be met. For the example well considered in this study, it was found that almost 30% of the total vertical section had good moveable oil potential. This corresponded to 10 intervals in the well. The key novelty of this paper is that we have developed a continuous curve of an index that is easy to use and is powerful for identifying intervals with moveable hydrocarbon potential. This is true even in those intervals without laboratory data because of the continuity of the curve, in addition to the integrated criteria that are usually applied independently. The Igp index is a simple–to–use approach. However, because it is a new method, an explorationist should validate it against real oil production information.
The course provides an introduction to Coalbed Methane from a basic understanding through to exploration, appraisal and development of the resource. History: Where did CBM come from and where is it established. Exploration: where to start, what data is required and how to get it. Appraisal: What is involved in the appraisal process of a CBM resource. Well design: There are many different varieties of CBM well design, and they result in different physical and environmental "footprints".
Summary This research focuses on membrane‐separation efficiencies by adjusting the ionic composition of deoiled produced water (PW) and evaluates the possibility for smartwater production from PW for enhanced oil recovery (EOR) in carbonate reservoirs. Key characteristics of smartwater for carbonate reservoirs are increased concentrations of divalent ions and low concentrations of monovalent ions compared with seawater. In this research, PW was pretreated with media filters, which resulted in 96 to 98% oil removal. This deoiled PW was used as feed for nanofiltration (NF) membranes. Combinations of NF retentate with seawater as feed and NF permeate from PW were considered. PW NF permeate, mixed with seawater spiked with multivalent ions, sulfate (), or phosphate (), is expected to alter the wettability of oil reservoirs. NF‐membrane performance was evaluated in terms of flux and the separation efficiencies of the key scaling ions calcium (Ca) and barium (Ba). The tested membranes removed 60% of Ca and 53% of Ba, thereby reducing the scaling tendency. No membrane fouling was observed during the experiments. NF‐treated PW was analyzed for solubility of calcium carbonate (CaCO3). The results showed no Ca dissolution, which could affect chalk‐reservoir compaction. This research also reflects the use of nonprecipitating for smartwater production, simultaneously decreasing the Ba concentration and the scaling potential of PW. The results obtained conclude that spiking below 12 mM showed no indication of chalk dissolution during equilibration tests at room temperature. Experiments performed with 44 mM of resulted in calcium phosphate [Ca3(PO4)2] precipitation. A process scheme is proposed for smartwater production by ionic selection from seawater and PW at an operating pressure of 18 bar. Energy‐consumption analysis for smartwater production before membrane treatment concluded NF to be economic over other desalination technologies. The power consumed by NF membranes for smartwater production at 18 bar is calculated at 0.88 kW·h/m, whereas the power consumed is 51.22 and 103.52 kW·h/m for reverse osmosis (RO) and multistage flash distillation (MSF), respectively.
Abstract The deposition of carbonate and sulphate scales is a major problem during oil and gas production. Managing scale with chemical application methods involving either scale prevention and/or removal are the preferred methods of maintaining well production. However, chemical scale control is not always an option, depending upon the nature of the reservoir and well completion and, in cases of severe scaling, the problem can render chemical treatments uneconomic unless other non-chemical methods are utilised. A variety of non-chemical scale control methods exist, the most common being injection of low salinity brines or low sulphate seawater (LSSW) using reverse osmosis and a sulphate removal plant (SRP) respectively. In addition, careful mixing of lift gas, produced waters and reinjection, coatings, smart well completions with active inflow control devices (ICD) and sliding sleeves (SS) are other methods. All of these techniques, including combinations thereof, are currently in use and the advantages and disadvantages of the key techniques are compared to chemical methods for both carbonate and sulphate scale control. A detailed example from a North Sea field demonstrates where downhole chemical scale control has not been required through a strategy of careful mixing of lift gas, brines and produced water re-injection. This was combined with understanding fluid flow paths in the reservoir and their likely breakthrough at production wells. Consideration is given to the injection of smart brines to scale deep in the reservoir, and data from North Sea chalk fields shows how "in situ" geochemical reactions between the reservoir and the injected fluid can precipitate sulphate scales. The necessity to understand these geochemical reactions and their implications for improved oil recovery and the design of smart injection brines for scale control are discussed. This paper presents a comprehensive review of non-chemical methods for downhole scale control and discusses how the use of these techniques can provide alternative scale management strategies through minimising or alleviating the need for downhole chemical treatments.
Hu, Yisheng (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Mackay, Eric (Heriot-Watt University) | Vazquez, Oscar (Heriot-Watt University) | Ishkov, Oleg (Heriot-Watt University)
Summary In waterflooded reservoirs under active scale management, produced-water samples are routinely collected and analyzed, yielding information on the evolving variations in chemical composition. These produced-water chemical-composition data contain clues as to the fluid/fluid and fluid/rock interactions occurring in the subsurface, and are used to inform scale-management programs designed to minimize damage and enable improved recovery. In this interdisciplinary paper, the analyses of produced-water compositional data from the Miller Field are presented to investigate possible geochemical reactions taking place within the reservoir. The 1D and 2D theoretical model has been developed to test the modeling of barium sulfate precipitation implemented in the streamline simulator FrontSim. A completely 3D streamline simulation study for the Miller Field is presented to evaluate brine flow and mixing processes occurring in the reservoir by use of an available history-matched streamline reservoir-simulation model integrated with produced-water chemical data. Conservative natural tracers were added to the modeled injection water (IW), and then the displacement of IW and the behaviors of the produced water in two given production wells were studied further. In addition, the connectivity between producers and injectors was investigated on the basis of the comparison of production behavior calculated by the reservoir model with produced-water chemical data. Finally, a simplified model of barite-scale precipitation was included in the streamline simulation, and the calculation results with and without considering barite precipitation were compared with the observed produced-water chemical data. The streamline simulation model assumes scale deposition is possible everywhere in the formation, whereas, in reality, the near-production-well zones were generally protected by squeezed scale inhibitor, and, thus, the discrepancies between modeled and observed barium concentrations at these two given wells diagnose the effectiveness of the chemical treatments to prevent scale formation.
Abstract The production experience from the Statfjord Field on the Norwegian Continental Shelf is one of the greatest adventures in modern oil and gas history. After achieving very high oil recovery factor using a predominant drainage strategy with pressure maintenance by water and gas injection, the drainage strategy in the field has since 2007/2008 been changed to reservoir depressurization. Prior to depressurization start-up, the field has produced about 652 million Sm (4.1 billion bbl) oil and 187 billion Sm gas. Currently, the field is producing at an oil rate of approximately 5 300 Sm/d and a gas rate of about 11 million Sm/d. Estimates indicate that successful implementation of the new drainage strategy will continue and lead to an ultimate oil recovery of higher than 67% and a significant additional gas production, as a result of the depressurization process. In addition, the field life will be extended from 2009 to 2025, and this will contribute to lifetime extension of the attached satellite fields. The main purpose of this paper is to provide a description of the multidisciplinary approach used for evaluation and planning of the Statfjord Late Life (SFLL) with reservoir depressurization, share learnings from depressurization start-up and address challenges, uncertainties and opportunities.
The PDF file of this paper is in Russian.
The production experience from the Statfjord Field on the Norwegian Continental Shelf is one of the greatest adventures in modern oil and gas history. After achieving very high oil recovery factor using a predominant drainage strategy with pressure maintenance by water and gas injection, the drainage strategy in the field has since 2007/2008 been changed to reservoir depressurization.
Prior to depressurization start-up, the field has produced about 652 million Sm3 (4.1 billion bbl) oil and 187 billion Sm3 gas. Currently, the field is producing at an oil rate of approximately 5 300 Sm3/d and a gas rate of about 11 million Sm3/d. Estimates indicate that successful implementation of the new drainage strategy will continue and lead to an ultimate oil recovery of higher than 67% and a significant additional gas production, as a result of the depressurization process. In addition, the field life will be extended from 2009 to 2025, and this will contribute to lifetime extension of the attached satellite fields.
The main purpose of this paper is to provide a description of the multidisciplinary approach used for evaluation and planning of the Statfjord Late Life (SFLL) with reservoir depressurization, share learnings from depressurization start-up and address challenges, uncertainties and opportunities.
Abstract A technical-economic research was done evaluating microfiltration polymeric membranes and cartridge filters as pretreatment of Sulfate Removal Units (SRU). These units were installed in a Stationary Production Unit (SPU) to reduce the concentration of sulfate from seawater (injection water in Enhanced Oil Recovery). The use of seawater with low sulfate in enhanced oil recovery reduces the risk of sulfate deposits during the oil production. Ten companies from different nationalities involved in the industrial water treatment and manufacturing of polymeric membranes sector, have contributed to this comparative research (only a preliminary stage of the future study with qualitative and quantitative analyses). This paper shows that polymeric microfiltration is more advantageous because reduce operational costs and microbiological contamination resulting in a lower risk of biofouling. It also improves the quality of treated water, increases the operational stability and availability of the injection water, extending the lifetime of the nanofiltration polymeric membranes.