Mature Oil Field Research Articles

Performance of enlarging swept volume by Surface-active Polymer flooding for enhancing oil recovery

ABSTRACTSurface-active Polymer is a novel multifunctional active polymer for chemical flooding in mature oilfield, and the mechanism of enhancing oil recovery by Surface-active Polymer flooding is to be further studied. Performance of enlarging swept volume for enhancing oil recovery by Surface-active Polymer flooding has been evaluated in this paper. The effect and contribution rate of mobility control of Surface-active Polymer flooding for enhancing oil recovery were tested firstly, and then microscopic experiments on enlarging swept volume based on microetching models have been carried out, and macroscopic evaluation of enlarging swept volume based on heterogeneous models with cores grouped in parallel was carried out. Mobility control effect and plugging by emulsifying make Surface-active Polymer have significant performance of enlarging swept volume. Enlarging swept volume both on the macroscopic and the microscopic is the basic principle of Surface-active Polymer flooding for enhancing oil recovery.

Model calibration and optimization of a post-combustion CO2 WAG pilot in a mature oil field

A carbon dioxide (CO2) water-alternating-gas (WAG) pilot was conducted to gain insights into tertiary oil recovery potential via CO2 flood in the West Ranch Field as part of the Petra Nova project, the world's largest post-combustion CO2 capture and utilization initiative. With a fluvial formation geology, this is a challenging and novel application of CO2 enhanced oil recovery. The aim of this study is two-fold. First, to build a predictive dynamic model that incorporates the data acquired during the pilot operation. Second, to utilize this model to provide guidance for optimal design for a field-wide CO2 EOR operation.This study began with an initialization of the pilot sector model extracted from a calibrated full-field model. The pilot model calibration follows a two-step hierarchical workflow. First, we performed a large-scale update of the permeability distribution by integrating available bottomhole pressure and multiphase production data. Next, local permeability field is fine-tuned using a streamline-based method to match CO2 breakthrough times at the producers. The predictive capability of the calibrated model was verified through two blind validation tests: (1) the model showed good agreement with saturation logs acquired at two observation wells; and (2) the model reproduced the CO2 recovery as a fraction of the injected CO2.Sensitivity studies were conducted using the calibrated pilot model to evaluate the effects of various operational parameters. Finally, we performed a Design of Experiment based multi-objective optimization of the CO2 WAG processes using the influential operational parameters identified from the sensitivity analysis.

Establishing a link between composition and toxicity of offshore produced waters using comprehensive analysis techniques – A way forward for discharge monitoring?

Extracts of produced waters from five mature Norwegian Sea oil fields were examined as total organic extracts (TOEs) and after fractionation into operationally-defined ‘polar’ and ‘apolar’ fractions. The TOEs and fractions were examined by gas chromatography (GC), GC-mass spectrometry (GC–MS), two dimensional GC–MS (GC × GC–MS) and liquid chromatography with high-resolution spectrometry (LC-HRMS) techniques.Low molecular weight aromatics, phenols and other common petroleum-derived hydrocarbons were characterized and quantified in the TOEs and fractions. In addition, a range of more uncommon polar and apolar constituents, including those likely derived from production chemicals, such as trithiolane, imidazolines and quaternary amine compounds (so-called ‘quats’), were tentatively identified, using GC × GC–MS and LC-HRMS.The acute toxicity of the TOEs and subfractions was investigated using early life stages of the marine copepod Acartia tonsa. Toxicity varied significantly for different PW TOEs and subfractions. For some PWs, the toxicity was attributed mainly to the ‘polar’ components, while that of other PWs was associated mainly with the ‘apolar’ components. Importantly, the observed toxicity could not be explained by the presence of the commonly reported compounds only.Although, due to the vast chemical complexity even of the sub-fractions of the PW extracts, specific compounds driving the observed toxicity could be not be elucidated in this study, the proposed approach may suggest a way forward for future revisions of monitoring regimes for PW discharges.

Stability assessment of PITT tracer candidate compounds – The case of pyrazines

The determination of the residual oil saturation (SOR) in the volumes swept between injector/producer well pairs is a parameter of major importance for the design and/or evaluation of IOR projects. The number of IOR projects is increasing with the growing number of mature oilfields. The partitioning inter-well tracer test (PITT) is used to measure SOR in waterflooded reservoirs and relies on the use of partitioning and passive tracers. Many PITT were unsuccessful in the past due to a poor knowledge about the compounds used as tracers and to date, very few compounds were developed for this application. New partitioning tracers are needed, and a systematic qualification process is necessary to reduce the risk of costly unsuccessful field tests. In the present document we report and discuss the findings from stability experiments performed on 2 alkylpyrazines, 1 methoxypyrazine, and 2 halogenated pyrazines under investigation for use as oil/water partitioning tracers for determination of the SOR in the inter-well region of water flooded oil reservoirs.The stability of 2,3-dimethylpyrazine, 2,6-dimethylpyrazine, 2-methoxypyrazine, 2-chloropyrazine, and 2-fluoropyrazine in brine solutions was evaluated in batch experiments at temperatures ranging from 25 °C to 150 °C for 12 weeks, at 3 different pH values and in the presence of typical oil reservoir rock materials (sandstone, carbonate rock, and clay). Results suggest that 2,3-dimethylpyrazine and 2,6-dimethylpyrazine possess the required stability and absence of significant interaction with the rock substrates. 2-chloropyrazine and 2-fluoropyrazine degrade with a temperature and pH dependent rate but are not influenced by the rock materials. 2-methoxypyrazine exhibits temperature dependent degradation in the absence of any rock substrate and in the presence of sandstone and carbonate rock. A strong interaction was observed between this compound and the clay material (kaolinite) which is responsible for dramatically increasing its degradation rate.

A Recrosslinkable Preformed Particle Gel for Conformance Control in Heterogeneous Reservoirs Containing Linear-Flow Features

Summary Preformed particle gels (PPGs) have been successfully applied to control conformance for mature oil fields because of their advantages over conventional in-situ gels. However, field applications have demonstrated that current particle gels cannot efficiently plug open fractures, fracture-like channels, or conduits that exist in many mature oil fields. The objective of this study is to systematically evaluate a new recrosslinkable-PPG (RPPG) product that can be used to efficiently control the conformance for abnormal features. The RPPG can swell to 38 times its initial volume, and the equilibrium swelling ratio is independent of the brine salinity. Temperature and the particle size showed a gradient effect on the swelling rate of the gel. Additionally, the particle gels can recrosslink to form a rubber-like bulky material in the large-opening features after placement that significantly enhances the plugging efficiency. We systematically evaluated the effect of temperature and RPPG swelling ratio on the recrosslinking time, the gel strength after crosslinking, and the gel thermostability. Coreflooding tests were run to test whether RPPG can significantly improve the fracture-plugging efficiency compared with a traditional PPG that cannot recrosslink after pumping. The RPPG can be customized for mature reservoirs with a temperature from 23 to 80°C with a controllable size from tens of nanometers to a few millimeters. The recrosslinking time can be controlled from 2 to 80 hours, depending on the swelling ratio and temperature. The gel elastic modulus after recrosslinking can achieve from 300 to 10 800 Pa, depending on the swelling ratio and the temperature. Coreflooding tests showed that the breakthrough pressure of the recrosslinked RPPG can reach up to 300 psi/ft for a fracture with a 0.2-cm aperture, which is more than five times higher than that of the conventional PPG.

Isolated mechanism study on in situ CO2 EOR

In situ CO2 enhanced oil recovery (ICE) has great potential for the mature oil field. ICE can deliver CO2 to the targeted formation by the injection of CO2 producing agents which decompose in the reservoir to release CO2 and other oil recovery enhancing compounds. The mechanism of the ICE system was evaluated experimentally. Alkali and hydrotrope induced interfacial tension (IFT) reduction were studied with crude oils that have different acid numbers and also dodecane. The independent and combined effect of the ICE system on wettability reversal was quantified by contact angle measurement with different fluid systems and lithology. Ten one-dimensional sand pack flooding tests with different lithology and fluid systems were designed to isolate the different recovery mechanisms and study their individual contribution to the final tertiary recovery. From the experimental results, the highest IFT reduction by alkali effect was from 21 mN/m to 0.77 mN/m. The wettability of clean sandstone and sandstone aged in crude oil were responsive to different concentrations of NH3 solution. The sandstone surface became more water-wet with increase in NH3 (aq) concentration. The wettability of carbonate core samples were not strongly affected by the NH3 solution. Both aged sandstone and carbonate core samples showed significant wettability reversal from oil-wet to water-wet after the ICE treatment. After a series of sand pack flooding tests, it was shown that the effect of CO2 was more dominant in carbonate reservoirs and NH3 (aq) contribution to the tertiary recovery increased with the increase of the crude oil acid number. The results help elucidate the mechanisms in ICE and their contribution to the final oil recovery.

Evaluation of total oil and grease with flow control for mature oil fields in the context of industry 4.0

Goal: Industry 4.0 enables the design of new models for process monitoring in which sensors, analyzers, and controls are positioned at different points in the process. The goal of this work is to present the modeling and control of a three-phase production separator with hydrocyclones to treat produced water on an oil platform of mature fields.
 Design / Methodology / Approach: The Methodology or approach used was to develop a model for the primary separator that allows its operation by means of a controller (fuzzy and PI) to manipulate the flow of discarded water, acting indirectly in the oil-in-water measure.
 Results: The results showed the consistency of the model for open loop simulations and the effectiveness of the controllers to comply with the discarding requirements for the closed-loop simulations. 
 Limitations of the investigation: The limitation of the model and developed controllers is that they are only applied to platforms where water production exceeds the separators discharge capacity and the exceeding water can be offloaded to another equipment or to another platform.
 Practical implications: The main practical implications of this study are to maximize the flow of discarded water on mature field platforms, which produces elevated amounts of water, to conform the total oil and grease to the local law regulations. Additionally, it also increases oil production, with a higher limit of water production.
 Originality / Value: Compared to the previous authors, where the models of discarded flow is a function of the water-oil interface, this work developed a model that allowed the flow of the discarded water to be a function of its quality.

Casing Failure Characteristics, Prevention and Control Strate gies for Mature Oilfields

As the oil and gas fields enjoy a longer and longer production life, casing damaged wells in oil and gas fields increase year by year in number. Assets are at expense, costs are incr eased, and production is threatened. In this paper, the status and mechanism of casing failures in China, USA and Russia are investigated; factors and prevention and intervention measures ar e analyzed; casing failure types, intervals, times and causing factors are studied; failure charact eristics and causes types of mature oilfields are compared and evaluated; and for each different-factor that causes casing failure a corresponding prevention or intervention method is suggested. The studies on casing failure mechanism, detection technology and modeling by overseas countries are worth of reference, and correlative technologies are significant guidance for casing failure prevention and control in our mature oilfields.

U-Shaped Re-Entry Drilling Revitalizes Depleted Reservoirs Offshore Congo

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 191436, “Extended-Reach U-Shaped Re-Entry Drilling in Shallow, Depleted Fractured Reservoirs in Congo’s Oldest Offshore Oil Field,” by Mike Tony Chembou, Bruno Valeri, Lois de Crevoisier, Michel Akue, and Vincent Rodet, Perenco Congo, and Gabriele Ghia, Achille Mouamba, and Ali Lazzem, Schlumberger, prepared for the 2018 SPE Annual Technical Conference and Exhibition, Dallas, 24–26 September. The paper has not been peer reviewed. Against the background of a low-oil-price environment, a redevelopment project was launched to give a second life to a shallow, depleted, mature offshore Congo oil field with viscous oil (22 °API) in a cost-effective manner. The solution selected was to drill U-shaped side tracks (inclination at total depth=115°) from the original boreholes on an existing platform at a water depth of 60 m. The objective was to create a second drainage area. The project team used innovative, low-cost techniques to overcome many challenges. Geological Context and Objectives Under 27 platforms (four to five well-heads each), an accumulation of heavy, viscous oil is trapped in three reservoir layers. The field was produced with a combination of cold mode followed by a period of hot mode from steam injection. The consequence is a depleted (0.3-sg) and highly steam-fractured reservoir where fluid loss presents one of the primary challenges for infill development. The pilot project consists of re-entering the current producers and then deepening them in a U shape to access the same shallow reservoirs more than 200 m away from the initial production leg. All reservoirs share the same water table identified below an impermeable formation underneath the target layers. To avoid water breakthrough, the trajectories were planned with up to 18°/30 m to prevent the well from entering the water-bearing layer, with minimum 30-m true vertical depth standoff from the oil/water contact. Well Design and Architecture The well architecture is selected to match the existing mother-well construction. All selected re-entry candidates are producing wells showing the following well architecture: 9 5/8-in. casing set as intermediate casing at approximately 100 m measured depth (MD) below the rotary table A mixed string composed of cemented blank 7-in. casing and uncemented 7-in. slotted liner in front of the pay zones. An external casing packer (ECP) was installed between the two strings, and a cementing job was performed above the ECP. The float shoe at the bottom, therefore, was uncemented and prone to be untorqued during re-entry The completion system consisted of progressive-cavity-pump or sucker-rod-pump strings, depending on the wells. To fulfill the geological and reservoir objectives, the wells were re-entered by drilling a 6-in. hole section from a 7-in. float shoe to the U-shaped total depth before a 4½-in. liner was run. The sand-face completion evolved slightly from the first two wells (blank perforated) to the last three wells (slotted liner).

Fracture modeling from borehole image logs and water invasion in carbonate reservoirs with layer-bound fractures and fracture corridors

The objective of this paper is to demonstrate, how water invasion in unison with borehole images can be used to decipher fracture architecture in a carbonate reservoir with layer-bound fractures and fracture corridors. TVD vs. fracture density plots help in identification of highly fractured layers and establish mechanical and structural attributes that control layer-bound fracture density, height and orientation. Fracture corridor stick plots over structural map of the reservoir reveal whether fracture corridors are related to faults or folds. Flattop cross sections constitute the scaffold to construct fluid conductive fracture model in mature oil fields, where water has already started to creep up fracture corridors and encroach in high permeability or highly fractured layers.One of the prime applications of flattop cross sections is to evaluate connectivity of fluid conductive fractures. Fractured layers with interconnected open fractures have a high permeability and will be subject to water fingering. If water invasion bypasses such a fractured layer and advances into high permeability matrix streaks, in all likelihood open fractures within the fractured layer are not interconnected and hence are not fluid conductive. High water saturation coincident with a fracture corridor on a flattop cross section is a strong indication that the fracture corridor is fluid conductive and water rises up fracture corridors and spreads into the surrounding reservoir.

CO2 for EOR Combined with Storage in the Norwegian North Sea

The Norwegian Petroleum Directorate (NPD) presented a CO2 Storage Atlas for the Norwegian Continental Shelf (NCS) in 2014. The main objective with this Atlas was to identify safe and effective areas for long-term storage of CO2. There are more than 22 years of experience with storage of CO2 in geological formations offshore Norway and a lot of work has been done to map, characterize and evaluate potential storage sites. To get an overview of the possibility of using captured CO2 for enhanced recovery (EOR), several screening studies were conducted. The technology for CO2 used for EOR is well documented for onshore fields. Implementing CO2 for EOR offshore will be more challenging and can carry operational, commercial and financial risks. In this paper, we present the results from three different screening studies on storage of CO2 combined with EOR in oil fields in the Norwegian part of the North Sea and one residual oil study (ROZ) from an oil discovery in the Barents Sea. The input to these studies are production history and characteristics from the different oil fields and the results are based on reservoir simulation from screening studies on these fields. The results from these studies are purely technical, no detailed economic evaluation has been done. The aim was to study the possibility and potential of using CO2 for EOR on some of the mature offshore oil fields in combination with storing CO2 in the underground. All these studies showed very interesting results.

NANOFLUID INJECTIVITY STUDY FOR ITS APPLICATION IN A PROCESS OF ENHANCED OIL RECOVERY (CEOR)

The application of tertiary recovery techniques through chemical injection (CEOR) is in full development in the mature oil fields of Argentina. An experimental study of nanofluids intended for enhanced oil recovery is presented in this work. A polyacrylamide solution prepared in brine with addition of silica nanoparticles was used as the focus of the study. Dynamic sweep tests of the displacement fluids in a laboratory-scale triaxial cell using a standard Berea sandstone cores that simulates the formation of the reservoir allow the calculation of parameters related to its injectivity, which take into account damage to the formation and blockade of poral throats , such as the resistance factor (FR), the residual resistance factor (FRR), the inaccessible pore volume (VPI) and the dynamic retention of the nanofluid (RD). The injection of the nanofluid has not produced an increase in the damage of the porous medium, so it is potential for its application in the displacement of crude oil.

Simulation of the effect of rock type on recovery plan of a mature carbonate oilfield in the Middle East – Part 1: Waterflooding recovery plan

The X field is a mature carbonate oilfield in the Middle East, discovered in 1908. Several uncertainties exist in relative permeability data of the old X field, due to rock type diversity of the field. In this study, the effect of rock wettability on waterflooding process of this field is investigated by means of two reported wettability data sets of the field. Results show that initial rock wettability plays an important role in improving oil recovery, affecting production rate, recovery factor, breakthrough time, water cut, residual oil saturation, project life, etc.

Simulation of the effect of rock type on recovery plan of a mature carbonate oilfield in the Middle East – Part 2: EOR plan

Enhanced oil recovery (EOR) technology has gained a lot of attention during last decades. Declining oil production from brown fields is a major concern for oil companies. One of these mature fields is the X field, a carbonate oilfield in the Middle East, discovered in 1908. In this study, in addition to considering an EOR plan for the X field, it is aimed to investigate the effect of rock wettability on recovery process by means of two reported wettability data sets of the X field. Results of EORgui software show a sensitive dependence of oil recovery on initial rock wettability. Results of a laboratory chemical coreflooding experiment on the field core samples have been also included in the study.

Opportunities for a Low Carbon Transition-Deploying Carbon Capture, Utilization, and Storage in Northeast India

As development in India paces up, energy demand is projected to increase; exerting pressure on the environment and presenting the added challenge of mitigating greenhouse gas emissions at an accelerated pace. Carbon capture, utilization, and sequestration (CCUS) is one of the mitigation strategies that India could adopt in this context, in the backdrop of an energy industry largely dominated by coal. Specifically, the north-eastern state of Assam in India is home to large point sources of CO2 emissions like power, chemical or fertilizer plants, and has abundant sinks in the form of mature oil fields, coal beds, and saline aquifers. This work discusses the emission cuts that can be achieved by retrofitting existing point-sources with CCUS systems, and the techno-economic considerations thereof. We analyze how the levelized cost of electricity will change across three power plants, and how the economics of capture and avoidance costs at a chemical plant can revive its current financial situation, to present why there is an incentive for CCUS in Assam. The results show that for any CCUS implementation plant design, age and preparedness are factors that influence the economics and can lead to huge differentials. Since no new major expansions are planned in the region, investing in retrofitting will deliver immediate results towards achieving climate goals, while allowing time for the future deployment of renewable energy sources and energy storage solutions.

Nawadnianie mikrobiologiczne jako sposób zwiększenia stopnia sczerpania starych złóż ropy naftowej. Wyniki projektu i analiza efektywności ekonomicznej po 80 miesiącach trwania projektu

Nawadnianie mikrobiologiczne jako sposób zwiększenia stopnia sczerpania starych złóż ropy naftowej. Wyniki projektu i analiza efektywności ekonomicznej po 80 miesiącach trwania projektu

Polymer and nanoparticles flooding as a new method for Enhanced Oil Recovery

Abstract A new Enhanced Oil Recovery (EOR) method is proposed by combining the effects of a traditional polymer flooding and exploiting the advantages that nanotechnology presents in the oil industry. Thus, a novel technique is introduced and applied to a 2D reservoir model with a two-phase, five-component system (aqueous, oil phases and water, hydrocarbon, polymer, nanoparticles and salt). For the polymer characterization, a novel approach is presented considering the polymer's architecture and its degradation in order to calculate the physical properties, which has never been reported in reservoir simulation. The presence of the nanoparticles affects mainly the rheological behavior and the wettability of the rock, increasing the oil phase mobility. Moreover, negative effects such as particle aggregation and sedimentation are also modeled using a novel formulation in reservoir simulation. The combined action of polymers and nanoparticles allowed increasing the recovery factors beyond standard EOR processes, and it represents a suitable alternative to replace traditional combined methods, such as Surfactant-Polymer (SP) or Alkaline-Surfactant-Polymer (ASP). This is due to the fact that the nanoparticles act, to a greater or lesser extent, on the wettability, rheological and interfacial properties of fluids and rock formation, which is complemented with the polymer's viscosifying properties. Moreover, economical factors could also render this technique more attractive, since the nanoparticles' associated costs are substantially lower than those from surfactant flooding. This simulation proves the potential of nanotechnology as a mean to boost traditional EOR techniques in order to further increase the operative life of mature oil fields.

A Review of Field Oil-Production Response of Injection-Well Gel Treatments

SummaryAs life-span extenders, bulk gels have been widely applied to rejuvenate oil production from uneconomic producers in mature oil fields by improving the sweep efficiency of improved-oil-recovery (IOR)/enhanced-oil-recovery (EOR) floods. This paper presents a comprehensive review of the responses of injection-well gel treatments implemented between 1985 and 2014. The survey includes 61 field projects compiled from SPE papers and US Department of Energy reports. Seven parameters related to the oil-production response were evaluated according to the reservoir lithology, formation type, and recovery process, using univariate analysis and stacked histograms. The interquartile-range (IQR) method was used to detect the underperforming and overperforming gel projects. Scatterplots were used to identify the effects of the injected-gel volume and the treatment timing on the treatment response. Pretreatment water cut, recovery factor, and flood life were used as indicators for the treatment timing.Results indicated that gel treatments have very wide ranges of response for injection and production wells and for oil and water rates and profiles. When successfully applied, they, on average, respond after 3.5 months, increase the oil-production rate by 32%, and additionally recover 116,000 STBO per treatment, 15 STBO per gel barrel, or 10 STBO per polymer pound. We identified that gel treatments perform more efficiently in carbonate (CB) than in sandstone (SS) reservoirs and in naturally fractured (NF) formations than in other formation types. In addition, the incremental oil production considerably increases with the channeling strength and the injected-gel volume for all formation types, not just for the matrix-rock (MR) reservoirs. Moreover, gel treatments applied in NF formations have lower productivities in SS than in CB reservoirs using normalized performance parameters.Declining trends were identified for all parameters of the oil-production response with the treatment-timing indicators. The sooner the gel treatment is applied, the faster the response, and the larger the incremental oil production and its rate. It is recommended to allow longer evaluation times for gel treatments applied in MR formations because their response times might extend to several months. Gel treatments will perform more efficiently if they are conducted at water cuts of less than 70%, flood lives of fewer than 20 years, or recovery factors of less than 35%. For different application environments, the present review provides reservoir engineers with updated ideas regarding the low, typical, and high performances of gel treatments when successfully applied, as well as how other treatment aspects affect performance.

Rescaling-contraction with a lower cost technology when revenue declines

A mature oil field rescaled contraction describes a switch to a technological alternative more appropriate for the depleted state of an underlying resource. Off-shore oil rigs are an illustration, since the original technological scale designed for very large output flows becomes inappropriate as the operational efficiency declines later in life and facing a dwindling output flow, so a more appropriate extraction technology becomes economic. A real option representation is formulated on a stochastic oil price and deteriorating output volume. We consider investment/divestment decisions both separately, and jointly, which have different implications for government policies and also option values. The resulting model yields analytical (or semi-analytical) results indicating that immediate switching to the lower cost technology could sometimes be hastened as the price volatility increases, depending on the current revenue, if divestment and switching are considered jointly. However, greater volatility could also promote hysteresis.

Achievements and future work of oil and gas production engineering of CNPC

Abstract This paper summarizes the latest achievements and technological progress in oil and gas production engineering of China National Petroleum Corporation (CNPC) and discusses the main four challenges faced: developing low quality resource at low oil price; keeping stable production of mature oilfields when well oil production drops year by year; low systematic efficiency, high cost, prominent environmental protection issue and short of technological strategy for high water cut ratio and high oil recovery ratio oilfields; and lacking of high level horizontal well drilling and completion technology to develop unconventional and deep reservoirs. Three technological development directions to address these challenges are put forward: developing fracture controlling stimulation and well factory to produce low quality resource economically, developing re-fracturing technology for old wells in mature oilfields, promoting the fourth generation separate layer water injection technology to stabilize the production of mature oilfields; innovating new technologies of water flooding with nano-material, injecting and producing through one well.