Mature Oil Field Research Articles

ANN-Based Prediction of Laboratory-Scale Performance of CO2-Foam Flooding for Improving Oil Recovery

Improving oil recovery by CO2 injection continues to gain momentum in mature oil fields due to its favorable industrial and environmental benefits. One remediation for the poor sweep efficiency of CO2 is co-injection of surfactants to generate CO2-foams in reservoirs. However, it is essential to minimize the expensive and time-consuming experiments required during the laboratory screening of this EOR process for a given reservoir. In this regard, methods to predict RF and Q from reservoir characteristics based on existing laboratory test data are worthwhile. In this paper, we develop the RF and Q prediction models involving optimized multi-layer perceptron (MLP) and radial basis function (RBF) neural networks. These models are applied to a compiled dataset of 214 data records of published CO2-foam injection tests into oil-reservoir cores. The RF and Q prediction derived applying these two models to the compiled dataset are compared. Statistical accuracy measures of the predictions achieved for an independent testing subset (20% of the data records) indicate for RF (MLP: RMSE = 0.0236, R2 = 0.9988; for RBF: RMSE = 0.0197, R2 = 0.9991) and for Q (MLP: RMSE = 0.0283, R2 = 0.9971; for RBF: RMSE = 0.0092, R2 = 0.9991) the excellent prediction performance of the developed networks.

Post-Combustion Carbon Dioxide Enhanced-Oil-Recovery Development in a Mature Oil Field: Model Calibration Using a Hierarchical Approach

SummaryWe present a simulation study of a mature reservoir for carbon dioxide (CO2) enhanced-oil-recovery (EOR) development. This project is currently recognized as the world's largest project using post-combustion CO2 from power-generation flue gases. With a fluvial formation geology and sharp hydraulic-conductivity contrasts, this is a challenging and novel application of CO2 EOR. The objective of this study is to obtain a reliable predictive reservoir model by integrating multidecadal production data at different temporal resolutions into the available geologic model. This will be useful for understanding flow units along with heterogeneity features and their effect on subsurface flow mechanisms, to guide the optimization of the injection scheme and maximize CO2 sweep and oil recovery from the reservoir.Our strategy consists of a hierarchical approach for geologic-model calibration incorporating available pressure and multiphase production data. The model calibration is performed using regional multipliers, and the regions are defined using a novel adjacency-based transform accounting for the underlying geologic heterogeneity. The genetic algorithm (GA) is first used to match 70-year pressure and cumulative production by adjusting pore volume (PV) and aquifer strength. Water-injection data for reservoir pressurization before CO2 injection is then integrated into the model to calibrate the formation permeability. The fine-scale permeability distribution consisting of more than 7 million cells is reparameterized using a set of linear-basis functions defined by a spectral decomposition of the grid-connectivity matrix (Laplacian grid). The parameterization represents the permeability distribution using a few basis-function coefficients that are then updated during history matching. This leads to an efficient and robust work flow for field-scale history matching.The history-matched model provided important information about reservoir volumes, flow zones, and aquifer support that led to additional insight compared with previous geological and simulation studies. The history-matched field-scale model is used to define and initialize a detailed fine-scale model for a CO2 pilot area that will be used to study the effect of fine-scale heterogeneity on CO2 sweep and oil recovery. The uniqueness of this work is the application of a novel geologic-model parameterization and history-matching work flow for modeling of a mature oil field with decades of production history, and which is currently being developed with CO2 EOR.

Development of fly ash reinforced nanocomposite preformed particle gel for the control of excessive water production in the mature oil fields

One of the appropriate methods to minimize water production and increase sweep efficiency is the utilization of Preformed Particle Gel (PPG) in the mature oil fields. In this paper, a new fly ash reinforced nanocomposite PPG was developed by the reaction of acrylamide as monomer, N,N′-Methylenebis (acrylamide) as crosslinker and nano fly ash in presence of Potassium Persulfate as initiator and it was compared with a conventional PPG which was designed without nano fly ash. On the incorporation of nano fly ash, swelling performance and thermal stability of PPG had increased significantly. Rheological data revealed that dynamic moduli (G′ and G″) of fly ash reinforced nanocomposite PPG has improved viscoelastic properties with a higher value of critical shear stress as compared to conventional PPG. The single sandpack flow experiment has shown the injectivity of nanocomposite PPG into the sandpack with a maximum resistance factor of 60.57. However, parallel-sandpack flow experiment showed that the newly developed nano fly ash reinforced nanocomposite PPG has a profile improvement rate of 92.98% and 97.83% for the permeability contrast of 2.16 and 4.14 respectively and hence it may be a promising agent in reducing excessive water production in mature oil fields.

Investigation of semi-interpenetrated networks gel for water production control in a mature offshore oilfield

Water flooding as the dominant method to improve oil recovery has been widely applied to most oilfields in the world; however, excess water production has become a major problem for reservoirs that have been flooded by water for many years. The objective of this paper is to prepare and evaluate a novel strong gel that can be used to significantly reduce the permeability of the fluid channels resulting from water flooding. We developed a novel fluid diversion agent called CPP gel, which is a semi-interpenetrated networks gel cross-linked by acrylamide grafting onto sodium carboxymethyl cellulose/polyglycol. The paper investigated its applicability with the Bohai offshore oilfield reservoir conditions. The gel properties, including the rheological performance and blocking efficiency, as well as its influencing factors were investigated. The results showed that the CPP had less injection pressure but higher blocking efficiency than conventional polymer gels, and its blocking efficiency was dependent on the gel components, temperature, water salinity, rock permeability and rheological properties. The decrease in the network chain length, the increase in the interactions among molecules and the increase in the uniformity of the overall network structure could contribute to the enhanced blocking mechanisms. [Received: February 7, 2015; Accepted: January 28, 2017]

Investigation of semi-interpenetrated networks gel for water production control in a mature offshore oilfield

Investigation of semi-interpenetrated networks gel for water production control in a mature offshore oilfield

ENHANCED OIL RECOVERY (EOR) USING CO2, MITIGATING CLIMATE CHANGE AND PROLONGING MATURED OIL WELLS: A PERSPECTIVE FOR NIGERIA

Are we running out of fossil fuel? If so, how fast is this happening? How are policies and technologies responding to these changes? And what are the alternatives? Today, global policies towards fossil fuel production are rapidly changing towards stringent means (owing to the debate on global climate change) in that “arguably” the change is brought by the release of anthropogenic CO2 into the atmosphere. A change towards reducing the amount of CO2 flared during petroleum production into the atmosphere by employing technologies that can capture CO2 and transport it to matured oil fields has the potential of increasing reserves while achieving a paradigm towards cleaner and environmentally friendly production as well as mitigating climate change. This paper presents a propose perspective for the Nigerian E & P sector in mitigating the scourge of climate change, adaptive for smarter future growth and prosperity in an cost effective manner through the capture of anthropogenic CO2 and injecting it back into matured oil wells for enhance oil recovery (EOR).

Геохимическое состояние почв длительно разрабатываемых месторождений Среднего Приобья (на примере Родникового месторождения)

Геохимическое состояние почв длительно разрабатываемых месторождений Среднего Приобья (на примере Родникового месторождения)

Revival of mature onshore oil field in U.S.

During planning stage of CO2 EOR （enhanced oil recovery）, evaluation of remaining oil volume is one of the most important works because of its significant impact on field performance and project economics. However, the evaluation becomes very challenging when the concerned field is a legacy field where historical data are insufficient unless reliable data were later supplemented. We describe how to evaluate CO2 EOR project for a legacy field with insufficient historical data.

Plenty of Room at the Bottom: Nanotechnology as Solution to an Old Issue in Enhanced Oil Recovery

During the past half-century, the prefix “nano” attached to several words, such as “technology”, “motors”, “device”, and so on has denoted cutting-edge research fields and topics at the forefront of classical scientific disciplines. Possible application fields have been frequently evoked, even if real-life examples are still difficult to find. The present review analyzes how nanotechnology is utilized in enhanced oil recovery (EOR) processes so as to increase the efficiency of mature oilfields. Nanotechnology in EOR is classified into three categories: nanoparticles/nanofluids, nanoemulsions, and nanocatalysts. The advantages at the nanoscale are also described and discussed, including an overview of manufacturing methods as well as the concerns about their possible environmental impacts. Clearly, nanotechnology has the potential to boost EOR techniques, although there are still many questions and drawbacks to be tackled.

Sensitivity analysis in using of artificial neural network models to determine infill well locations in a mature oil field

This paper describes a method to rank potential infill well locations using Artificial Neural Networks (ANN) from existing well data. Sensitivity test was conducted for training and testing data used with comparison 2:8, 4:6, 5:5, 6:4 and 8:2 for each data. Root Mean Square Error difference between training and test data show that the best results obtained from the ratio of training data and testing data 8: 2. Two ANN models were built. The first model predicted top sand depth, resistivity, gamma-ray and density-neutron from infill well location (chosen from structural position and good oil rates from offset wells). The second model predicted initial oil rate from outputs from the first model. Predicted initial oil rates from the ANN model were compared with those from the 3D reservoir simulation model. They shows similar prediction of oil rates which gave high confidence in the predicted oil rate. Very different oil rate prediction between the two models can be used as consideration to improve the simulation model.

Development and exploration practice of the concept of hydrocarbon accumulation in rifted-basin troughs: A case study of Paleogene Kongdian Formation in Cangdong sag, Bohai Bay Basin

Abstract Based on the merged 3D seismic data, well logging, formation testing, analysis and testing data, the structural evolution, sedimentary reservoirs, thermal evolution of source rocks were investigated of Paleogene Kongdian Formation in the trough area of Cangdong sag, Bohai Bay Basin. A conventional-unconventional hydrocarbon accumulation pattern in the trough area of rifted basin was revealed. The reservoir forming elements in the trough area of Cangdong sag have a zonation feature in terms of reservoirs and source rocks. There are two types of reservoir forming models, primary trough and reformed trough. The formation and evolution of trough controlled the orderly distribution of conventional oil to unconventional oil in the trough. Particularly, structural reservoirs occur in the upper part of the trough, stratigraphic-lithologic reservoirs are likely to form in the delta front deposits at the outer ring of trough, the middle ring transitional belt is the favorable site for tight oil reservoirs, while the fine grain deposits zone in the inner ring is shale oil and gas exploration area. The study has pointed out the new domains and directions for searching reserves in the secondary exploration of mature oilfields.

Synergistic Mechanism of Hydrolyzed Polyacrylamide Enhanced Branched-Preformed Particle Gel for Enhanced Oil Recovery in Mature Oilfields

Branched-preformed particle gel (B-PPG) is a novel agent for EOR application in mature reservoirs. To improve the enhanced oil recovery (EOR) performance of B-PPG, the heterogeneous combination flooding system composed of B-PPG, hydrolyzed polyacrylamide (HPAM), and surfactant was proposed. However, the synergistic mechanism of B-PPG and HPAM still remains unclear. Here, a series of experiments were performed to study the viscosities of HPAM, B-PPG, and mixture of HPAM and B-PPG, evaluate the suspension stability of B-PPG and mixture of HPAM and B-PPG, to investigate the propagation behavior of HPAM, B-PPG, and a mixture of HPAM and B-PPG through porous media, and to study the EOR performance of HPAM, B-PPG, and a mixture of HPAM and B-PPG in heterogeneous reservoirs by performing parallel sand pack flooding experiments. Results show that the suspension stability of B-PPG can be improved by adding polymer due to the increase in viscosity. The higher the HPAM concentration is, the higher viscosity of mixtu...

EFFECT OF OPTIMUM SALINITY?ON MICROEMULSION FORMATION TO ATTAIN ULTRALOW INTERFACIAL TENSION FOR CHEMICAL FLOODING APPLICATION

Microemulsion formation in surfactant solution has a major influence on the success of chemical injection techniques, and is one of the enhanced oil recovery methods. Its transparent and translucent homogenous mixtures of oil and water in the presence of surfactant have an ability to displace the remaining oil in the reservoir by reducing interfacial tension between oil and water. In this study, the effect of surfactant solution salinity on the formation of microemulsion and its mechanism to reduce the interfacial tension between water and oil from X oil field in Central Sumatera were carried out through compatibility observation, phase behaviour test and interfacial tension measurements in a laboratory. The results showed that microemulsion formation depends on the salinity of aqueous phase associated with different surfactant solubility by altering the polar area of surfactant. The optimum salinity was obtained with the addition of 0.65% Na2CO3 in which microemulsion was formed and the solubilization ratio of oil and water were equally high. At this condition the ultralow interfacial tension was around 10-3 dyne/cm and enabled improved oil recovery in mature oil fields after waterflooding

Dispersed Particle Gel-Strengthened Polymer/Surfactant as a Novel Combination Flooding System for Enhanced Oil Recovery

A novel dispersed particle gel-strengthened polymer–surfactant (DPS) combination flooding system was proposed and demonstrated for enhanced oil recovery in high water cut mature oilfields. As compa...

Ceramic Sand Screens Applied in Maturing Oil Field Offshore Malaysia

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 188537, “First Successful Application of Ceramic Sand Screen in Maturing Oil Field, Offshore East Malaysia,” by Sulaiman Sidek, SPE, Kellen Goh Hui Lian, Yap Bee Ching, Kukuh Trjangganung, Bahrom Madon, SPE, and Zainuddin Yusop, Petronas, and Bhargava Ram Gundemoni, SPE, Richard Jackson, and Peter Barth, 3M Technical Ceramics, prepared for the 2017 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 13–16 November. The paper has not been peer reviewed. This paper presents the first successful application of ceramic sand screens offshore Malaysia. Ceramic sand screens were considered as a remedial sand-control method because of their superior durability and resistance compared with metallic sand screens. Remedial sand control with ceramic sand screens has successfully revived idle wells back to production at a lower total cost, with oil gain beyond the initial target and a higher return on investment. Field Overview The field was discovered in July 1967 at a water depth of 250 ft below mean sea level approximately 40 km offshore East Malaysia. The structural configuration of the field is characterized by a simple, low-relief domal anticline resulting from the rollover associated with regional growth faulting. Major hydrocarbon accumulation occurs in eight producing reservoirs sandwiched between shallow gas-bearing reservoirs and deeper gas- and condensate-bearing reservoirs. Since peak production in 1979, the field has experienced instances of sand production, contributed to by factors such as in-situ stress changes, increases in water production, and a cascading effect from production-operation activities. The current practice of controlling severe sand production is to bean down the problematic wells and closely monitor sand production at surface over time. Some of the field’s wells had experienced failure and rapid wear when using metallic sand screens, so ceramic screens, with high erosion resistance, were proposed. Because this represented the first such application for the operator, a pilot application was considered for three wells. Ceramic Sand Screens Sintered silicon-carbide ceramic material offers unique combination properties. Greater hardness, compressive strength, and elastic modulus offer superior ballistic capability and resistance to wear when confronted with high-velocity projectiles. Excellent corrosion resistance provides high performance in corrosive environments. High thermal conductivity provides heat stability (up to 1,800°C) and minimizes the likelihood of failure caused by thermal shock. The low specific density of the material makes it suitable in applications in which weight requirements are critical. When the erosion- and corrosion-resistant properties of ceramic material are holistically integrated within a sand-control system, the resultant screen installation is proved to be simple and cost-effective, resulting in reduced complexity compared with alternative sand-control methods. Conventional metallic materials exhibit limitations in with-standing high downhole velocities, commonly resulting in downhole erosional failure and premature loss of downhole sand control.

Possibility of decreasing CO2 emissions from flaring on a mature oil field

Analysis of change in composition of flaring gas during the exploitation period of an oil reservoir has been performed to estimate possibilities for feasible reduction of CO2 emissions during hydrocarbon production. There are many projects regarding improvements of energy and flare efficiencies or possibilities for CO2 separation and storage, but none of them calculates emissions for different p-T conditions. Numerous oil fields do not have possibilities for transport of gas separated during oil production to final consumers due to technological or economic limitations. This paper deals with possibility of introducing small technological improvement like implementation of gas separator, which might lead to CO2 reduction at flare. First, it was necessary to calculate accurate oil production decline through lifetime of a reservoir, then pressure decline for a mature oil field was correlated. The payout period for such improvement, along with other economical parameters, has been calculated in economic analysis. It can be concluded that CO2 reduction is possible and economically feasible by introducing separator at oil production field.

Optimized Cyclic Water Injection Strategy for Oil Recovery in Low-Permeability Reservoirs

With the worldwide decline in conventional oil production, tremendous unconventional resources, such as low-permeability reservoirs, are becoming increasingly important. Cyclic water injection (CWI) as an oil recovery method has attracted increasing attention in the present environment of low oil prices. However, the optimal CWI strategy is difficult to determine for a mature oilfield due to the involvement of multiple wells with multiple operational parameters. Thus, our main focus in this paper is to present a novel and systematic approach to optimize CWI strategies by studying a typical low-permeability, namely, reservoir G21. To this end, a comprehensive method that combines the advantages of streamline simulation and fuzzy comprehensive evaluation (FCE) was proposed to identify water channeling in the reservoir. Second, the reliability of the method was verified using tracer tests. Finally, a new hybrid optimization algorithm, the simulated annealing-genetic algorithm (SAGA), coupled with a reservoir simulator was developed to determine an optimal CWI strategy for the low-permeability reservoir. The results show that the CWI technique is viable as a primary means in the present environment of low oil prices to improve the waterflood performance in low-permeability reservoirs. The oil recovery of the most efficient strategy increases by 6.8% compared to conventional waterflooding. The asymmetric CWI scheme is more efficient than the symmetric CWI scheme for the low-permeability reservoir.

The Role of Enhanced Oil Recovery in the Upstream Petroleum Sector, a Turkey Case

The upstream petroleum sector issues still keep its popularity worldwide. Enhanced Oil Recovery (EOR) is an essential unconventional method of improving production in the petroleum sector. The EOR is gaining more importance in the sector. 2% of the global crude oil production is performed by EOR operations currently. The crude oil production of Turkey which is now in a decreasing trend is performed from old and mature oil fields. Sharp declines are expected for the oil production in the near future if new discoveries do not take place or enhanced oil production techniques are not performed. The average recovery rate for the crude oil fields in Turkey is about at 20%. An increase in this ratio can provide significant amount of crude oil to Turkish production. The ratio of crude oil production by EOR methods is about 15% currently in Turkey. In this study, the historical background of EOR projects is explained and potential EOR methods have been discussed for Turkish crude oil fields. The aim of the research is to evaluate the crude oil production potential from existing oil fields of Turkey based on EOR methods matching with the characteristics of oil fields with statistical information on world EOR outlook.

New progress and prospect of oilfields development technologies in China

As technologies advance in oilfield development, mature oilfields are able to keep sustainable production and complex oilfields difficult to produce in the past are put into production efficiently. In this work, new progresses of main development technologies for medium-high permeability and high water cut, low permeability, heavy oil, complex faulted block and special lithology reservoirs in the past decade, especially those international achievements made in enhanced oil recovery, were summarized, the key problems and major challenges that different oilfields are facing were analyzed, and the development route and direction of three-generation technologies were proposed as “mature technology in industrialized application, key technology in pilot test and innovative technology for backup”. The key research contents should focus on: (1) Fine water flooding and chemical flooding for mature oilfields, improving oil recovery after chemical flooding, and gas flooding for low permeability reservoirs must be researched and tested in field further. (2) Study on subversive technologies like nanometer smart flooding, in-situ upgrading and injection and production through the same well should be strengthened. (3) EOR technologies for low oil price, new fields (deep sea, deep layer, unconventional reservoirs etc.) and highly difficult conditions (the quaternary recovery after chemical flooding, tertiary recovery in ultra-low permeability reservoirs) should be stocked up in advance. The development cost must be lowered significantly through constant innovation in technology and reservoir management to realize sustainable development of oilfields.

Numerical analysis of carbon dioxide injection into a high permeability layer for CO2-EOR projects

Mature oilfields and aquifers are the most favorable targets for the CO2 sequestration projects. In this work, the purpose is to investigate an alternative approach in which at very early stage of the oil production, combines CO2-EOR and CO2 sequestration up to the depletion of the oilfield, and analyze the relationship between EOR and CCS projects. Responding to the oil industry needs, initially was designed to investigate the potential to increase the oil recovery factor and the extent to which mobility overlaps the miscibility in reservoirs with low and high permeability layers, a situation which is similar to the pre-salt reservoirs. The process of CO2 injection into oil reservoir is analyzed in different flooding scenarios that include: (i) continuous gas injection (CGI), (ii) constant water-alternating-gas (WAG) injection, and (iii) tapered WAG (TWAG) injection. Compositional numerical simulations were conducted to identify the good injection site in the reservoir and to optimize the injection strategies. Based on the observation, the results reveal that the oil recovery factor may be employed for indicating whoever overlaps, between mobility and miscibility, when a high permeability layer is present. A cradle-to-grave life cycle analysis was considered for estimating net CO2 emissions in each of the CO2-EOR operations. In regards to CCS, in the CGI, WAG and TWAG, simulation results indicate that the CO2 stored represents around 28.77%, 14.49% and 13.24% of the CO2 emissions, related to the oil produced due to the implementation of the EOR project, respectively.