The basic objective of this course is to introduce the overview and concept of production optimisation, using nodal analysis as a tool in production optimisation and enhancement. The participants are exposed to the analysis of various elements that help in production system starting from reservoir to surface processing facilities and their effect on the performance of the total production system. Depth conversion of time interpretations is a basic skill set for interpreters. There is no single methodology that is optimal for all cases. Next, appropriate depth methods will be presented. Depth imaging should be considered an integral component of interpretation. If the results derived from depth imaging are intended to mitigate risk, the interpreter must actively guide the process.
Heavy and extra-heavy crude oil reservoirs hold physicochemical characteristics that can frequently turn their operation into a technical and economic challenge. Typically, heating techniques are used to decrease oil viscosity. Areas with steam injection are susceptible to developing formation damage mechanisms such as scale precipitation that gradually restricts the flow of fluid towards the wellbore and ultimately decreases overall well productivity and/or injectivity. Acidizing treatments to either remove obstructing scale or to further increase near wellbore permeability are handled with caution: heavy oil is very sensitive and interaction with such conventional acids include asphaltene precipitation, sludge and emulsions.
Suplacu de Barcau is a shallow, heavy oil reservoir (16°API average) located in the northwestern part of Romania. It has been successfully operated with aid of both in-situ combustion and steam injection since 1960. Scaling tendency of condensed water from steam and its incompatibility when mixed with formation water frequently ends in scale build-up in injector and producer wells respectively. Identifying a fluid able to clean-out the scale deposits while being fully compatible with sensitive heavy oil, involved extensive screening a compatibility testing protocols. A formulation based on the chelating agents N,N, Glutamic Acid Diacetic Acid (GLDA) and Diethylene Triamine Pentaacetic Acid (DTPA) were found not only to effectively dissolve the plugging materials, but remarkably it was also noticed that it reduced significantly the oil viscosity, which made this formulation the most appropriate treatment for field application.
A number of 10 producer wells treated with the GLDA and DTPA based fluids delivered promising results by increasing oil rates by 3- 6 times of increase, significant improving steam coverage and penetration, decreasing drawdown and skin and ultimately enhancing the mobility of asphaltic oil. This paper describes the stimulation approach followed from diagnosis, fluid screening and selection, treatment design, job execution and results. Furthermore, the outcome of this stimulation campaign has shattered the myth that this type of stimulation does not work in hard oil.
A numerical simulation study was conducted to explore feasibility of gas cap and oil column co-development plans. Unlike conventional development schemes that entail to optimally produce first from oil column while deferring gas cap development, the co-development strategy studied here involves simultaneous production from oil column and gas cap. The drive mechanism consists of down-dip peripheral water injection for oil column in conjunction with barrier water injection at or near gas-oil contact that is designed to separate the gas cap from the oil column and thereby facilitate gas production. The basic objective of the study is twofold: to assess the merits of the concept of barrier water injection and to identify key subsurface and operational parameters that have most significant impact on oil and gas recovery. Extensive numerical simulations were conducted to explore the conditions under which the concept of barrier water injection is favourable as a recovery process. Important issues related to the viability of the development concept are how fast a barrier water can be established, how long it can be sustained and how many wells are needed. Furthermore, effects of gas cap relative size, reservoir geometry (e.g., dip-angle and surface area of the gas-oil contact), trapped gas, rock heterogeneity and off-take rates have been investigated in detail. The work shows that the feasibility of the co-development scheme is mainly controlled by pressure maintenance and balance of injection, relative size of gas cap, reservoir geometry and rock heterogeneity.
Polymer flooding is a mature Enhanced Oil Recovery process which is used worldwide in many large- scale field expansions. Encouraged by these positive results, operators are still looking at applying the process in new fields even in the context of low oil prices and are evaluating its feasibility in more challenging reservoir conditions: high salinity, high hardness and high temperature. Several solutions have been proposed to overcome the limitations of the conventional hydrolyzed polyacrylamide (HPAM) in these types of challenging environments: biopolymers such as xanthan or scleroglucan, associative polymers, or co- or ter-polymers combining acrylamide with monomers such as ATBS or NVP. Each of these solutions has its advantages and disadvantages, which are not always clear for practicing engineers. Moreover, it is always interesting to study past field experience to confront theory with practice. This is what this paper proposes to do.
The paper will first review the limits of conventional HPAM and other polymers that have been proposed for more challenging reservoir conditions. But more than that, it will focus on the field experience with each of these products to establish some practical guidelines for the selection of polymers depending on the reservoir and fluid characteristics.
One first result of this review is that the limits of conventional HPAM may not be as low as usually expected. Biopolymers appear very sensitive to biodegradation and their success in the field has been limited. Associative polymers appear better suited to near-wellbore conformance control than to displacement processes and some of the new co and ter-polymers are currently being field tested with some measure of success. It appears that the main challenge lies with high temperature rather than high salinity; some field projects are currently ongoing in high salinity (200 g/L) and hardness.
The paper will help set the current limits for polymer flooding in terms of temperature, salinity and hardness based on laboratory work and field experience. This will prove a useful guide for practicing engineers looking to pilot polymer injection in challenging reservoir conditions.
We explore the possibility to use digital rocks to determine poroelastic parameters which are difficult to extract from well-log or laboratory measurements. The Biot coefficient and the drained pore modulus are important in the compaction problem. The pore modulus represents the ratio of pore volume change to confining pressure when the fluid pressure is constant. In laboratory experiments, bulk volume changes are accurately measured by sensors attached to the outer surface of the rock sample. In contrast, pore volume changes are notoriously difficult to measure because these changes need to quantify the pore boundary deformation. Hence, accurate measures of the drained pore modulus are challenging. We simulate static deformation experiments at the pore-scale utilizing digital rock images. We model an Ottawa F-42 sand pack obtained from X-ray micro-tomographic images. We calculate the change in pore volume using a new post-processing algorithm, which allows us to compute the local changes in pore volume due to the applied load. This process yields an accurate drained pore modulus. We then use an alternative estimate of the drained pore modulus. We exploit its relation to the drained bulk modulus and the solid phase bulk modulus (i.e., Biots coefficient) using the digital rock workflow. Finally, we compare the drained pore modulus values obtained from these two independent analyses and find reasonable agreement.
Presentation Date: Thursday, October 18, 2018
Start Time: 8:30:00 AM
Location: 202A (Anaheim Convention Center)
Presentation Type: Oral
ABSTRACT: Wellbore instability and formation sand production pose potential risks for wellbore drilling, completion and production operations. In many sandstone reservoirs worldwide, sand production has been observed to accompany oil and gas production. In this study, we aim to estimate, predict and quantify wellbore instability and sand production potentials in the Hajdúszoboszló field, Pannonian Basin, Hungary, using the Mechanical Earth Model (MEM). Our study relies on petrophysical log data obtained from an onshore gas well within the field as input data. Our 1-D MEM utilizes a workflow that develops wellbore and sand failure mechanisms, first creating the mechanical stratigraphy of the reservoir rock; followed by estimating the pore pressure, overburden stress, rock strength, rock elastic properties, and horizontal stresses of the reservoir rock with reference to the depth of stratigraphic column, from compressional slowness, shear slowness, density, porosity and shale volume. Lastly, we conduct a wellbore stability and sand management analysis. Our results show the mechanical stratigraphy of unconsolidated sandstone and shale distribution in the reservoir, wellbore shear and tensile failures, wellbore breakout and breakdown pressures, wellbore sensitivity analysis, sanding interval analysis, critical drawdown pressure (CDDP) profile and sand failure zones. Based on careful observation of our results, we predict the wellbore intervals with high sand production potentials and wellbore instability within the reservoir formations. Therefore, we suggest significant wellbore failure during drilling process and also a high possibility of sand production into the wellbore during well completion at a formation interval of 550-937 m. Although there is need for data from additional wells in the field to be incorporated into our model prediction, we suggest that our preliminary model can be useful for critical decision making during drilling and completion operations across the Hajdúszoboszló field, Pannonian Basin, Hungary. In addition, our study provides a platform for further investigation into wellbore stability and sanding analysis in other parts of the Pannonian Basin where available well data can also be incorporated in our model.
Carbon dioxide (CO2) flooding is a mature technology in oil industry, which finds broad attention in oil production during tertiary oil recovery (EOR). After five decade’s developments, there are many successful reports for CO2 miscible flooding. However, operators recognized that achieving miscible phase is one of big challenge in fields with extremely high minimum miscible pressure (MMP) after considering the safety and economics. Compared with CO2 miscible flooding, immiscible CO2 flooding demonstrates the great potentials under varying reservoir/fluid conditions. A comprehensive and high-quality data set for CO2 immiscible flooding are built by collecting various data from books, DOE reports, AAPG database, oil and gas biennially EOR survey, field reports and SPE publications. Important reservoir/fluid information, operational parameters and project performance evaluations are included, which provides the basis for comprehensive data analysis. Combination plot of boxplot and histogram are generated, where boxplots are used to detect the special cases and to summarize the ranges of each parameter; histograms display the distribution of each parameter and to identify the best suitable ranges for propose guidelines.
Results show that CO2 immiscible flooding could recover additional 4.7 to 12.5% of oil with average injection efficiency of 10.07 Mscf/stb; CO2 immiscible technique can be implemented in light/medium/heavy oil reservoirs with a wide range of net thickness (5.2 - 300 ft); yet in heavy oil specifically reservoir (oil gravity <25 °API) with thin layer (net thickness< 50 ft) is better.
In 2017 MOL celebrated the 80th anniversary of the first HC discovery of Hungary within the current territory of the country. This long history is coupled with also a long history of different EOR experiments and projects. Laboratory tests already started in the fifties followed by field applications in the sixties. The objective of this paper is to introduce the currently ongoing EOR related projects based on MOL's EOR history by highlighting the key technologies and projects.
Puskas, S. (MOL Hungarian Oil and Gas Plc.) | Vago, A. (MOL Hungarian Oil and Gas Plc.) | Toro, M. (MOL Hungarian Oil and Gas Plc.) | Ordog, T. (MOL Hungarian Oil and Gas Plc.) | Kalman, G. (MOL Hungarian Oil and Gas Plc.) | Hanzelik, P. (MOL Hungarian Oil and Gas Plc.) | Bihari, Zs. (MOL Hungarian Oil and Gas Plc.) | Blaho, J. (MOL Hungarian Oil and Gas Plc.) | Tabajdi, R. (University of Szeged) | Dekany, I. (University of Szeged) | Dudas, J. (University of Pannonia) | Nagy, R. (University of Pannonia) | Bartha, L. (University of Pannonia) | Lakatos, I. (University of Miskolc.)
Central element of MOL Hungarian Oil and Gas Plc. (MOL) US strategy is to increase the hydrocarbon production at Hungarian oil and gas fields using technologies that are more efficient. The main goals of this activity are to increase the recovery factor in fields depleted with extensive water flooding, improving efficiency of recovery technologies. For this purpose, new materials and technologies should be developed and applied at both Hungarian and foreign matured oil fields. That is the biggest challenge of the research and development (R&D) activity of the MOL Upstream. The R&D project began more than ten years ago to meet these challenges and increase the oil recovery factor of the Algyo field, which is the largest Hungarian oil field. This paper describes how a countless number of surfactants, co-surfactants and their mixtures were synthetized, developed and tested in the laboratory to achieve the objective, developing a combined surfactant-polymer (SP) flooding technology. The most important properties of these complex fluids were the thermal stability at reservoir conditions (98°C and 170 bar), the colloid chemical stability in electrolyte medium (formation water) and the compatibility with reservoir rock and pore filling fluids. The primary findings of this job show that several surfactants were effective at high temperature; low salinity reservoir conditions and have good solubilisation and displacement effect and low interfacial tension and low reversible adsorption on reservoir rock. Synergetic effect was observed between surfactants and polymers therefore surfactant-polymer mixtures were produced and tested in core flooding tests. Based on numerous displacement tests on reservoir core plugs it can be stated that the calculated recovery factor was 20-25% using the developed SP mixtures. The successful laboratory displacement tests were also reproduced by numerical simulation on numerical core samples as well as the injectivity test on the new 3D reservoir model that was carried out to see the effect of developed SP mixture under real reservoir conditions. This paper will present the results of several years of research and development work for SP formulation targeting SP flooding in high pressure and high temperature reservoir. The field implementation through an injectivity test will also be presented demonstrating that injection of 2,000 m3 SP solution has huge effect on oil production even 3 years later. Based on the outstanding field results a SP flooding pilot was started in 2016.
Lakatos, I. (University of Miskolc, Research Institute of Earth Scieces) | Lakatos-Szabo, G. (University of Miskolc, Research Institute of Earth Scieces) | Szentes, G. (University of Miskolc, Research Institute of Earth Scieces)
Reservoir conformance control (RCC) might be fundamental designingprofitable production technology in oilfields. Appropriate application of RCC methods can significantly results inimproved IOR/EOR throughreduced water production and profile correction. In the past decades, numerous techniques were extensively applied with these goals including macro- and microgels, emulsions, sols, crystalline compounds, etc. Surprisingly, the use of silicates was not really appreciated by the operators despite the fact that silicates were proposed for chemical EOR and profile control already in 1922. In the past decades, the silicate technology has a revival because of their outstanding features and these methods are superior to other gel technical solution. The review is summarizing both the old and the new results of laboratory research and the case histories. Recently, emblematic professionals proposed the silicate gels as efficient alternatives to other gel technologies. As a result, the attitude towards the extensive use of silicates in oil fields changed. Therefore, the presentation overviews the silicate conformance treatments and its advanced hybrid systems. They were used more than hundred times in Hungary, Serbia, Norway, USA, Oman, and other countries for water shutoff, profile correction, restriction of gas conning, mitigation of vertical CO2 migration in wells, remediation of leak-off by fractured casing, stimulation of wells operating in harsh environment, and mobility control in CO2 flooding.
The presentation summarizes the results of pilots and routine applications, and critically analyzes the lessons to learn. Base on the publications disseminated until now it can be concluded that the field jobs demonstrate outstanding statistics. It will also be shown that the diverse silicate RCC methods may attract attention because they can be efficiently used with high flexibility in all types of porous and fractured reservoirs. The in-situ formed silicate gels have excellent thermal stability up to 150°C, the chemicals are available at low price, the job needs simple surface facility, customary human force, and the methods are environmental friendly. Consequently, the silicate methods may open new vistas in brown field operations curing problems arising at oil and gas fields even in time of volatile oil and gas price.