Produced water composition analysis provides evidence of what geochemical reactions are taking place in the reservoir. This information can be useful for predicting and managing oilfield mineral scale resulting from brine supersaturation.
This paper presents results of a study of the produced brine compositions from three wells in a field operated in the North Sea, with geochemical modelling complementing the analysis. The findings presented in this work provide evidence of magnesium depletion and sulphate retardation in a sandstone reservoir at 130° C.
This adjusted formation water composition was then used for calculations of the injection water fraction in each of the produced water samples. The Reacting Ions Toolkit was used to plot data in a variety of formats, including ion concentration vs. ion concentration, ion concentration vs. injection water fraction and ion concentration vs. time to identify trends and to examine the extent of involvement of the various ions in geochemical reactions.
The breakthrough of sulphate, a component primarily introduced during seawater flooding, was retarded during injection water breakthrough. Observed sulphate concentrations were lower than predicted for the case of brine/brine interactions only. The implication of this sulphate reduction was lower minimum inhibitor concentration required to control scale formation and longer squeeze treatment lifetimes for the operator.
A brine/rock interaction mechanism was proposed that involves magnesium depletion and is reproduced in the reactive transport model. 1D reactive transport modelling was performed to match possible
The practice of squeeze treatments to oil/gas production wells to prevent inorganic scale formation has been applied for over 30 years and during that period different mechanisms to retain the inhibitor chemical have been evaluated. The simple mechanism of inhibitor retention, adsorption/desorption has been complemented over the years by enhanced adsorption via mutual solvent and full precipitation of the active inhibitor onto the mineral surface of the reservoir.
Previously published studies have shown that the retention of phosphonate scale inhibitors in sandstone reservoirs can be enhanced through the addition of a ‘squeeze life enhancer’. This chemical, typically, a highly charged, low molecular weight polymer can be applied in either the preflush or overflush stage of the scale squeeze treatment. To date these studies have been conducted using low temperature (85°C) sandpack testing.
This paper details the laboratory work carried out under high temperature (146°C) field conditions to qualify the use of the squeeze life enhancer for field application.
The results of the formation damage/inhibitor return corefloods using an MEA phosphonate (EABMPA, Ethanolaminebis(Methylene Phosphonic Acid)) and polymeric squeeze life enhancer additive are presented. The coreflood results indicated that the addition of the additive within the overflush stage of the squeeze program resulted in a 19% extension of the inhibitor lifetime. The ability to extend the squeeze treatment was translated into reduced injected squeeze fluid treatment volume as injected fluid volumes was an issue for the wells being treated and therefore reduced associated oil deferment costs.
The paper will also present field data obtained from the initial two field trial treatments which were carried out in a North Sea field. The trial well had been treated more than ten times previously with the same MEA phosphonate as applied in the enhancer trial making direct comparison of the treatment performance possible. The treatment program applied to the wells resulted in no change to the clean-up rates of the treated well and no process upset during well reflow. The initial scale inhibitor returns from the field trial treatments showed the expected improvement suggested from the coreflood study.
The study brings value to the industry by providing the process to follow for qualifying and trialling a new technology in a challenging high temperature scaling environment with the results from the field supporting the carefully designed chemical selection and evaluation program.
The effects of H2S on system integrity, sulphide scaling potential and health and safety in oil and gas production is well recognized and understood. However, as part of a wider study on pH dependent scale predictions, the authors have identified an additional challenge associated with the presence and/or development of H2S in reservoirs containing carbonates: higher H2S concentration reflects in higher calcium carbonate scaling potential. The intention of this work is to demonstrate the impact of H2S using a real field case scenario and investigate how the variability in water cut, aqueous phase composition, CO2 and H2S concentration can impact the well carbonate scaling potential and ultimately its productivity.
To model pH dependent scales correctly, it is necessary to integrate PVT calculations with the aqueous phase thermodynamic mineral scaling calculations. This has been extensively discussed in previous publications by the authors. For this work, a commercial integrated PVT and scale prediction software package was used to determine the scale prediction profile from reservoir to the first stage of topside separation. In addition, to investigate the impact of PVT on the final results, a second PVT software employing a different equation of state (EOS) is used and the results obtained from this calculations are coupled with the same aqueous phase model using the Heriot-Watt scale prediction workflow.
The well selected for this study shows productivity issues as well as signs of presence of calcium carbonate scale. However, scale prediction calculations carried out in the past did not show any potential for carbonate scale formation at the given conditions. After rigorously accounting for variations in water cut over time, as well as for increased H2S due to reservoir souring, our work clearly shows a correlation between a gradual loss of well productivity and carbonate scaling potential.
This work clearly demonstrates the impact of H2S on calcium carbonate scaling potential and highlights the importance of correctly modelling CO2 and H2S partitioning in gas/oil/water at the different stages of production, from reservoir to topside separation. Following this study, it has also been possible to offer specific well treatment and testing recommendations to verify the results and try to obtain improvements in production efficiency.
Moreover, the application of our approach to a real field scenario shows how some field findings associated with carbonate scale problems can be explained only by correctly modelling the full three phase system (oil, gas and water). Some aspects of this approach are frequently overlooked and not linked correctly to carbonate scale formation.
In this work, we show a case study of using fire flooding process in thin interbeded heavy oil reservoirs to tackle the problems of low oil production rate, low gas oil ratio, and low oil recovery factor in later stage of cyclic steam stimulation (CSS) operations. The fire flooding process was adopted for the Block D reservoir in Liaohe Oilfield, China.
The depth of Block D heavy oil reservoir is 800-1200m. The reservoir includes 30-40 thin layers in vertical direction, with average thickness of 2.2m per layer. Through laboratory experiments, numerical simulation, and analysis of surveillance data from the initial small scale field pilot, we improve the understanding of fire flooding recovery mechanisms in thin interbeded reservoirs. Then, technical limits such as reservoir thickness, number of layers and permeability contrast are established for successfully conducting fire flooding with high temperature oxidation. Reaction types identification methods based on corresponding field surveillance data are also proposed. Using such guideline, we have deployed fire flooding expansions in Block D reservoir with more well patterns.
It has been proven that fire flooding process with the designed well patterns can improve recovery and sweep, and make the wells more productive with enhanced inflow from multiple directions. The process technical limits successfully guides us in properly expanding the project. Reaction type identification method further helps to perform continuous dynamic surveillance of the high/low temperature oxidation burning state of the combustion front in the field. The initial pilot test includes 7 well patterns, which have been operational since 2005. Up to now, we have deployed a total of 105 fire flooding well patterns in Block D reservoir. Within the fire flooding area, the single-well oil production rate has doubled on average, with the reservoir pressure also doubled. For the multi-layered block D reservoir, the ultimate oil recovery factor for fire flooding can reach up to 55%, an increase of 28% from the expected recovery of CSS.
In conclusion, we have shown in this work that fire flooding process can be applied to deep thin to medium thickness interbeded heavy oil reservoirs. As a follow-up process in later stage of cyclic steam stimulation, it can significantly increase oil recovery and process performance.
Temizel, Cenk (Aera Energy) | Canbaz, Celal Hakan (Ege University) | Palabiyik, Yildiray (Istanbul Technical University) | Putra, Dike (Rafflesia Energy) | Asena, Ahmet (Turkish Petroleum Corp.) | Ranjith, Rahul (Far Technologies) | Jongkittinarukorn, Kittiphong (Chulalongkorn University)
Smart field technologies offer outstanding capabilities that increase the efficiency of the oil and gas fields by means of saving time and energy as far as the technologies employed and workforce concerned given that the technology applied is economic for the field of concern. Despite significant acceptance of smart field concept in the industry, there is still ambiguity not only on the incremental benefits but also the criteria and conditions of applicability technical and economic-wise. This study outlines the past, present and the dynamics of the smart oilfield concept, the techniques and methods it bears and employs, technical challenges in the application while addressing the concerns of the oil and gas industry professionals on the use of such technologies in a comprehensive way.
History of smart/intelligent oilfield development, types of technologies used currently in it and those imbibed from other industries are comprehensively reviewed in this paper. In addition, this review takes into account the robustness, applicability and incremental benefits these technologie bring to different types of oilfields under current economic conditions. Real field applications are illustrated with applications in different parts of the world with challenges, advantages and drawbacks discussed and summarized that lead to conclusions on the criteria of application of smart field technologies in an individual field.
Intelligent or Smart field concept has proven itself as a promising area and found vast amount of application in oil and gas fields throughout the world. The key in smart oilfield applications is the suitability of an individual case for such technology in terms of technical and economic aspects. This study outlines the key criteria in the success of smart oilfield applications in a given field that will serve for the future decisions as a comprehensive and collective review of all the aspects of the employed techniques and their usability in specific cases.
Even though there are publications on certain examples of smart oilfield technologies, a comprehensive review that not only outlines all the key elements in one study but also deducts lessons from the real field applications that will shed light on the utilization of the methods in the future applications has been missing, this study will fill this gap.
This paper describes novel electrochemistry based in situ heavy crude oil upgrading technology and also field case and results of In Situ Oil Upgrading from Visoke Heavy Oil Field, Albania, produced oil changing chemical composition results, as well as gains in crude oil production and reducing water cut. EOR technologies such as various thermal methods, CO2 flooding and chemical floods have gained increased interest due to the decreasing number of new-field discoveries, increasing number of maturing fields and higher oil price. Among the emerging EOR technologies, electro chemical Electric Enhanced Oil Recovery is the new generation of tertiary oil recovery enhanced by electro kinetics (electro osmosis) and electro chemistry. By tailored application of direct current on hydrocarbon reservoir between two wells, which serve as anode () and cathode (-), usually several fold oil production increase is achieved at cathode well, while production at anode well, if production well serves as anode, stays as before or slightly increased. Method, if anode and cathode wells are cased and perforated, does not require any work over for field application, just connecting control panel with power source (3 phase 380 V, 18 A, 50 or 60 Hz) and electrically connecting control panel with well heads (casing or tubing) which previously should be electrically insulated by insertion of resistive tube in production line.
Tham, Su Li (PETRONAS Carigali Sdn. Bhd.) | Ariffin, Mohd Hafizi (PETRONAS Carigali Sdn. Bhd.) | Johing, Fedawin (PETRONAS Carigali Sdn. Bhd.) | M Khalil, Muhammad Idraki (PETRONAS Carigali Sdn. Bhd.) | Dolah, Khairul Arifin (PETRONAS Carigali Sdn. Bhd.) | Yusop, Zainuddin (PETRONAS Carigali Sdn. Bhd.)
Water injection was implemented in a 30-year old brownfield offshore Sarawak, Malaysia in August 2016. Seawater is processed at a Water Injection Facility (WIF) and sent to four injectors, each injecting commingled into two or three different reservoirs. This paper discusses on challenges faced in initial start-up of water injection in a brownfield including the inability to meet target injection rate, frequent WIF trips and off-spec injection water, metering issues, as well as mitigation measures and lessons learned.
Initially, the injectors were able to take in only 33% of target injection volume as per the FDP plan. To remedy this, a ramp-up injection procedure was introduced to allow the injectors to gradually take in more water until the target injection rate could be achieved. A leaner and practical water quality SOP was devised to reduce injector downtime, particularly for satellite platforms, while ensuring water quality is not compromised. Injection fall-off testing was performed on the injectors to investigate the root cause of the injectivity issue through manipulation of downhole ICV. Through this exercise, it was discovered that the injection meters were not properly calibrated.
A combination of these methods proved successful in improving injection rate of the water injectors. Initial SOP developed for the injection water quality required testing of water quality at each sampling point including at unmanned satellite platforms, prior to recommencement of water injection post WIF shutdown. This is despite the duration of shutdown being shorter than the frequency of required sampling, which led to prolonged injection downtime. The requirement for water sampling for satellite platforms were modified to be less stringent while still maintaining good water quality. As a result, there was an improvement in WIF uptime from 92% in second month of injection to 99% in the fifth month.
The fall-off testing provided valuable information in terms of well and reservoir data. Careful and specific operational steps were required to adjust the downhole ICVs during fall-off testing, as opposed to hard shut-in of the water injectors which would cause backpressure and tripping of the WIF. Adjustment of the surface-controlled ICVs allowed sequential testing of different zones, which successfully shortened the total testing duration by 25%. The fall-off test also revealed that an injector was injecting into a reservoir which did not benefit any producers, and that the flowmeters for certain injectors were not calibrated properly.
Through these efforts, injection rates were successfully increased by 25 kbwpd, from 35% to 75% of the total injection target, within six months of its implementation. Water injection start-up challenges and mitigation methods are not often discussed in literature, such as adjustments needed to achieve target injection rate, operational steps in well testing for commingled injectors, and finding the optimum balance between quality and practicality of injected water testing. It is hoped that the issues and strategy in this field will serve as lessons learnt for upcoming water injection projects in this and nearby fields.
This case study presents results from 3D Gambia Blocks A1 and A4 Kirchhoff prestack depth migration (KPSDM) project offshore Gambia. The main purpose of this project is to produce a more accurate velocity model which would enhance event placement and improve the sediment events below Aptian unconformity. TTI anisotropic prestack depth migration and tomographic velocity updates including image guided (IG) and horizon constraint tomography are used. Because of the complex geology above the unconformity, the stratigraphic horizons were interpreted for the high-resolution tomography.
Presentation Date: Tuesday, October 16, 2018
Start Time: 9:20:00 AM
Location: Poster Station 21
Presentation Type: Poster
One of the primary goals of a 4D marine acquisition is to replicate the source/receiver positions of a previously acquired baseline so as to maximize repeatability. Some of the originally shot lines (often called prime lines) are reacquired to improve repeatability, usually depending on proximity to the prospect/reservoir and the availability of funds. The decision to re-acquire a line or a swath is commonly based on sub-surface coverage (fold) plots, dS (distance between sources) plots and/or dSdR (sum of distance between sources and distance between receivers) plots that are generated onboard as a part of standard QC during a 4D monitor acquisition. This can be quite subjective and expensive since we may end up acquiring more data than necessary.
To address this issue of cost versus data quality for 4D marine streamer monitor surveys, a methodology has been developed to aid decision making for real-time 4D acquisition optimization. This methodology uses redundant information from previous baseline/monitor surveys to help in the decision making of re-acquiring lines for an ongoing monitor survey.
Presentation Date: Tuesday, October 16, 2018
Start Time: 8:30:00 AM
Location: 204C (Anaheim Convention Center)
Presentation Type: Oral
An Excel-based tool was developed that uses cubic-equation-of-state (EOS) and thermodynamic electrolyte-chemistry modeling to assess sour-production streams from a reservoir, through production tubing, pipelines, and facilities to an export pipeline within a range of temperature and pressure conditions. The approach is need to assess the integrity risk posed to system components in the Alba field in the North Sea. To accurately determine multiphase sulfide concentrations, and therefore hydrogen sulfide (H2S) partial pressures and the resulting integrity threat in sour-production streams, it is first important to understand the pH-dependent distribution of the three species of sulfide that may be present in an aqueous solution. Many commercially available EOS software packages do not take into account aqueous pH- and speciation-driven aqueous sulfide solubility. They merely assume that the gas-phase and oil-phase H2S remains as H2S in all three phases and, as such, that the aqueous solubility is limited by the solubility of the H2S species in water.