This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 182450, “Production Optimization in Waterfloods With a New Approach to Interwell-Connectivity Modeling,” by Xiang Zhai, Tailai Wen, and Sebastien Matringe, Quantum Reservoir Impact, prepared for the 2016 SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, 25–27 October. The paper has not been peer reviewed.
In the complete paper, the authors present a novel methodology to model interwell connectivity in mature waterfloods and achieve an improved reservoir-energy distribution and sweep pattern to maximize production performance by adjusting injection and production strategy on the well-control level. The method involves a reduced-physics-based fast numerical tracer test on each well, which yields interwell connection strength or well-allocation factors (WAFs), and then a data-driven efficiency model on each interwell connection calibrated automatically from the injection and production history of the reservoir.
The approach combines and balances the advantages of both simulation and data-driven techniques. The approach models interwell connections based on a relatively mature waterflood history and performs fast forecast and waterflood optimization on the basis of the interwell-connection analysis. Injector/producer connections are identified by computing WAFs with a numerical tracer method. Then, a data-driven empirical efficiency model is adopted that de-fines the profile of the oil cut of each interwell connection, and reservoir-production history is used to calibrate the model. Therefore, each interwell connection is quantified with two critical parameters: WAF and connection efficiency. The reservoir model is simplified into a connection-based network model that can be used to predict oil and water production without use of rigorous time-dependent numerical simulation. A production-optimization algorithm is then implemented. The optimization objective is to minimize water production while maintaining oil-production rate, subject to a range of practical constraints. The production optimization is integrated into a numerical-simulation model, and a blind test is run for 6 months. A significant decrease in water production is observed.
Waterflood Surveillance. WAF. In the process of waterflooding, water is injected into injectors to displace remaining oil. In this water/oil communication system, incompressibility is assumed in fluid dynamics and reservoir rock. This assumption is equivalent to assuming that pressure communication between any two points in the reservoir is essentially instantaneous. The WAF quantifies the strength of connection between two wells of different types.
WAF is often computed by tracing streamlines and counting the number of streamlines between wells. However, the streamline-based method is incompatible with a dual-porosity system, and in general has poor performance in unstructured grids. The authors adopt a stationary numerical tracer method to compute WAF. The equations used in this process are presented in the complete paper.
Water Injection is a part of secondary recovery to sustain Reservoir pressure and improve sweep efficiency and consequently improve recovery factor of the field with minimum cost. Source of the water is varying between offshore and onshore fields.
Normally for all offshore fields, water injection source is sea water. However, it is vital to have proper water injection treatment system to avoid the risk of issues at surface and subsurface levels.
This case study will show how water injection treatment system is important and their impact on the decrease of water injection efficiency due to plugging and corrosion. In addition, it will show the proper mitigation plan for improvement of water quality for short/mid and long term planning of the field development.
Injected sea water should be treated mainly from the following parameters: Sand solids from the sea using the sand filters Oxygen removal from corrosion Bacteria’s Chemical inhibitors.
Sand solids from the sea using the sand filters
Oxygen removal from corrosion
Each of these parameters was checked and improved on the field and successful results were observed in terms of pipeline conditions and injection sustainability.
Due to the poor water quality, every year 15-20 water injectors were plugged or decreased dramatically due to water quality. Improving the quality of the water and setting the proper guidelines for the treatment standards showed a positive impact on injection sustainability and consequently improved production offtake from the field.
The holistic approach of the water injection treatment system and mitigation plan become possible uses the right standards of the treatment and correct surface facility. This will help to sustain water injection rate and decrease the number of acid jobs performed due to a decrease of the performance. Solving the cause of the problem is crucial instead of acting on the consequences.
Park, Hyemin (Hanyang University) | Park, Yongjun (Hanyang University) | Yeonkyeong, Yeonkyeong (Hanyang University) | Kim, Joohyung (Hanyang University) | Lee, Wonsuk (Korea Institute of Geoscience and Mineral Resources) | Kwon, Oukwang (Korea National Oil Corporation) | Sung, Wonmo (Hanyang University)
When low-salinity water containing SO42- is injected into carbonate oil reservoirs, rock dissolution and in-situ precipitation occur as chemical equilibria are progressed, altering both permeability and wettability. The Ba2+/Sr2+ ions present in the formation water as impurities chemically react with the SO42- ions, and BaSO4 and SrSO4 are precipitated. In addition, when injected low-salinity water including SO42-, either dissolution of Ca2+-containing minerals or CaSO4 precipitates are occurred. These reactions can cause a serious impact on the efficiency of enhanced oil recovery (EOR). Therefore, the main purpose of this study was to identify EOR efficiency induced by low-salinity waterflooding (LSWF) when Ba2+/Sr2+ were present in a carbonate oil reservoir.
From the results of the effluent analysis and material balance calculation with the produced Ba2+, Sr2+, and Ca2+ concentrations, when Ba2+/Sr2+ concentrations were low, permeability was improved because of rock dissolution predominating over in-situ precipitation. These results concurred to the permeability change which was calculated with the measured pressure data. Also, in the analysis of wettability alteration through the measurements of contact angles and relative permeabilities before and after LSWF, higher concentrations of impurities consumed more SO42- in precipitating BaSO4 and SrSO4, resulting in weaker wettability alteration due to the reduction of sulfate activity. These phenomena ultimately influenced EOR efficiency, i.e., the oil recovery was greater as Ba2+/Sr2+ concentration were lower. Therefore, applying LSWF containing SO42- ion to carbonate oil reservoirs is not always a desirable EOR method when Ba2+ or Sr2+ is present, as an impurity, in the formation water.
This paper aims at evaluating the interactions between gravity segregation and viscous fingering during water injection into viscous oils, in order to estimate the recovery factor accurately, e.g. before assessment of tertiary EOR mechanisms. Based on simulations of homogeneous and heterogeneous reservoir sector models with horizontal wells, we wish to identify the dimensionless groups affecting the water breakthrough time and the oil recovery, and to quantify the impact of viscous instabilities in 3D domains versus 2D vertical cross-sections.
High-resolution numerical simulations, based on very fine grids and a high-order spatial discretization scheme implemented in our parallel in-house research reservoir simulator, were required to properly capture the complex flow patterns of these two-phase immiscible displacements. We analyze the competition between viscous and gravity effects using different values of injection flow rate, oil viscosity, density difference between oil and water and domain aspect ratio. This analysis is carried out in 2D and 3D, for simple permeability distributions with different correlation lengths, by inspection of production data and saturation maps.
For the investigated range of parameters, capillary effects are negligible and we identify three flow regimes before water breakthrough. When gravity dominates, viscous fingering is strongly attenuated by the rapid formation of a gravity tongue but a ‘ridge instability’ phenomenon may occur. In contrast, when viscous forces are preponderant, the gravity tongue is very weak or non-existent, and the flow pattern in vertical cross-sections is often characterized by one dominant viscous finger. In the transition regime, the gravity tongue and the viscous fingers coexist and may reach the producer quasi-simultaneously, leading to an optimum injection velocity in terms of breakthrough sweep efficiency. We then examine the dependency of water breakthrough and oil recovery upon the end-point mobility ratio and the viscous-to-gravity ratio
In the context of viscous oil recovery by water injection, high-resolution simulations are required to represent the interplay between gravity segregation, viscous fingering and permeability heterogeneity. In the present study, under low capillary effects, it is quite remarkable that the post-breakthrough recovery is well predicted by 2D simulations and is mostly controlled by two dimensionless groups. This may be useful to create screening models for quick-look estimation of oil recovery on different sector models representative of an oil field.
Yim, Y. (Petroleum Institute) | Haroun, M. R. (Petroleum Institute) | Al Kobaisi, M. (Petroleum Institute) | Sarma, H. K. (University of Calgary) | Gomes, J. S. (ADNOC E&P) | Rahman, M. M. (Petroleum Institute)
Smartwater flooding is a promising oil recovery technique, demonstrating positive results in many laboratory and field tests, by altering salinity and ionic composition of injection water. Injection of smartwater in carbonate reservoirs has gained interest due to its potential feasible application, taking advantage of improved oil recovery. Electrokinetic enhanced oil recovery (EK-EOR) is another rising technology that involves passing low D.C. current through the reservoir between a subsurface anode and cathode in the producing well. It has demonstrated a number of advantages including fluid viscosity reduction, permeability enhancement and reduced water cut. Our formulation aimed at advancing their combined mechanisms through a novel hybrid EOR. This study is the first attempt to present the experimental work on Smartwater Flooding integrated with the application of Electrokinetics (EK).
The effects of total salinity, reducing monovalent ions (Na+ and Cl-) and spiking of multivalent anions (SO42-) on the crude oil/brine/rock interaction were studied. Zeta potential tests were integrated with core flooding experiments systematically designed to identify the optimum ionic concentration and current density. Optimization of current density was essential for controlling both Cl2 gas generation and formation damage. EK showed positive effects with our designed Smartwater, when optimum currentdensity was induced, allowing earlier production and incremental displacement efficiency of 2.4-6%.
This paper discusses how surveillance data are collected and integrated to assess the effectiveness and optimize the management of an offshore waterflood, and describes how an enhanced understanding of well performance, flow behaviour and reservoir architecture is used to optimize production and injection.
A comprehensive reservoir surveillance plan is essential in order to understand reservoir behaviour and to optimize ultimate recovery. Multiple surveillance techniques are used including pressure build up and fall off tests, production logs, cased hole formation resistivity and saturation logs, and wireline formation pressure measurements which provide critical information on reservoir connectivity in wells drilled after production start-up. Voidage replacement ratio (VRR) is carefully tracked in each reservoir unit. Hydrogeochemical modelling is used to understand the water chemistry interaction between injected water and formation water, and diagnostic methods such as Hall plots are used to assess injection well performance before and after well stimulation.
Several challenges have arisen since the first wells were put on production. Two of the most significant have been, firstly, to maintain water injection for voidage replacement and, secondly, to understand the reasons behind unexpectedly early water breakthrough at the producing wells. Two case studies illustrate how information from well surveillance has guided the response to these challenges.
Abdel-Aleem, Mohamed Ibrahim (Petroleum Company Shell Egypt J/V) | Abdel-Mottleb, Mohamed Kamal (Petroleum Company Shell Egypt J/V) | Mohamed, Mohamed Sobhy (Petroleum Company Shell Egypt J/V) | El-Dardiery, Mahmoud Mohamed (Petroleum Company Shell Egypt J/V) | El-Din, Reda Aly Amer Badr (Petroleum Company Shell Egypt J/V) | Radhakrishnan, Gokulnath (Maxtube Limited) | Youssef, Etman (Maxtube Limited) | Fernandes, Alwyn (Maxtube Limited) | Khouly, Amr Al (Maxtube Limited)
In a first ever case within Shell assets worldwide, Badr Petroleum Company (Bapetco) - a Shell Joint Venture Company in Egypt, has embarked on a project of replacing a 20 km Water Injection network, originally constructed with Welded API 5L carbon steel pipe, with fiberglass lined API 5CT Threaded and Coupled tubing.
The original network is a conventional pipeline system of welded pipes transferring brine from 3 Water Source wells to 23 Water Injectors through the Egyptian Western Desert. The water is of a high salinity of 180,000 ppm saturated with dissolved oxygen up to 1,000 ppb before chemical treatment. After injecting oxygen scavenger the concentration of the dissolved oxygen is 100 ppb. As a result, Bapetco has been facing severe corrosion related failures in Water Injection flowlines. The 20 km surface pipeline network had to be totally replaced approximately once every two years.
Many of the Water Source and Water Injection wells in this network were completed using GRE lined tubing for internal corrosion protection. However, corrosion by-products from the carbon steel flowline were a cause for concern given the risk of plugging the reservoir.
Basic remedial solutions such as clamps, chemical inhibitions, patches etc. were carried out on the flowline. Nevertheless a more manageable approach was sought especially after reviewing the life cycle costs of maintaining the network and the impact of frequent drops in injection rates on the overall production from the field.
Bapetco embarked on an ambitious plan to use API 5CT Threaded and Coupled Steel Tubing internally lined with fiberglass for corrosion protection to replace the bare Carbon Steel pipeline. Shell's confidence in GRE lining has been established over 20 years of using GRE lined tubing downhole in 11 countries. This endeavor also helps Bapetco utilize unused inventory of tubing instead of additional capex required for flowline replacement with API 5L pipes manufactured from more exotic steel.
The integration of API 5CT specification threaded and coupled tubulars into Pipeline Engineering design, considering flow dynamics and make up compatibility with standard valves and fittings, is a huge challenge given the lack of applicable design codes, standards and Engineering common ground.
Special components were engineered to provide a transition between GRE lined tubulars and plain end unlined fittings and flanges. Also, pressure testing, pigging and connection make-up procedures were reviewed and/or revised to accommodate the use of GRE lined API 5CT pipes in flowlines.
This paper chronicles the history of the Water Flood project, the nature, reasons and consequences of the multiple corrosion failures and the failed corrosion mitigation strategies.
Furthermore, the paper will shed light on the techno-commercial analysis and engineering that forms the basis for this mammoth effort.
The impact of brine salinity and compositions on improving brine-dependent recovery processes has been an active research area over the past two decades. Various studies have demonstrated an improvement in oil recovery, attributed predominantly to the ability of the brine to alter rock’s wettability towards water-wetness. The proposed hypothesis is that the wettability of carbonate rocks is altered due to desorption of oil carboxylic groups from rock surfaces by the adsorbed sulfate, while the divalent cations are co-adsorbed.
We developed a reactive transport model to test this hypothesis and considered wettability alteration through geochemical interactions among brine, oil and rock surface. In this model, we used various reaction pathways to account for the competition between oil acid-groups and active ionson the rock surface. The equations developed from various reactions are coupled with multiphase flow equations to control flow functions that ultimately determine the oil recovery. The model we developed was used to investigate the effects of ionic variations during carbonate coreflooding experiments. Thereafter, we extended DLVO (Derjaguin, Landau, Verwey and Overbeek) theory of surface forces to explain the molecular interactions between rock−brine−oil system by generating interfacial disjoining pressure and interaction energy.
The model was tested by matching and predicting results from recently published flooding experimental studies related to ionically-modified brines conducted under single-phase and two-phase flow conditions. In these experiments, sulfate concentration in seawater was halved and quadrupled, and compared to injections of formation water and seawater. We found remarkable agreement with the produced ion histories reported from the single-phase tests, although there were delays in the produced sulfate concentration because of retention within the core. For two-phase experiments, the model yielded excellent replication of the produced ion histories and oil recoveries obtained during injection of various brines. Results show that increasing sulfate while maintaining the concentration level of other ions improved oil recovery up to 10% OOIP. However, when sulfate was reduced, neither additional oil was recovered nor sulfate ion production was delayed. Application of DVLO theory shows that disjoining pressure, which dictates the water film thickness, is extremely sensitive to sulfate content of the brine. Brines with more sulfate content exhibit higher disjoining pressure and energy barrier compared to brines with fewer sulfates. This suggests that increasing sulfate in the injected brine is essential to alter rock wettability.
Water injection is a part of secondary recovery factor and it helps to sustain reservoir pressure and maximize production offtake. In the offshore environment, water injectors are injecting sea water. This paper will show how to revive water injectors without utilizing the conventional stimulation and minimize the cost if investment.
Back flow of water injectors is one of the methodologies to increase injectivity index for water injectors as the main source of injection degradation is poor water injection quality, not chemical reaction inside the formation.
This paper will show the source of the water injection degradation along with "Back Flow" methodology and improvements after it.
The recovery from fractured reservoirs is usually low. The areal heterogeneity is one result of the fractured reservoir. Low-salinity waterflooding (LSWF) and preformed particle gel (PPG) have recently investigated by some reserchers. The main objective of this study was to determine whether the combining technologies can improve conformance control in fractured sandstone reservoirs. Semi-transparent five-spot models made of sandstone cores and acrylic plates were built. The effect of low-salinity waterflooding on oil recovery was studied. Models were designed with three parallel open fractures. Sodium chloride (1.0, 0.1, 0.01, and 0.001 wt. % NaCl) were used for brine flooding and 1.0 wt. % NaCl for preparing swollen PPG. Two microgel concentrations, 2000 PPM and 5000 PPM, with 850 micrometer particle size were used. Three cycles of low-salinity water were injected after the second conventional brine injection was completed. Oil recovery factor, water cut, injection pressure, microgel extruded pressure, fracture pressure (Pf), monitoring pressure (P1 and P2), and water residual resistance (Frrw) were measured. The interwell connectivity also was investigated. Laboratory experiments showed that the oil recovery factor, injection pressure, and the Frrw increased when the concentration of injected brine changed from conventional salinity to low salinity and the areal sweep efficiency was improved. The tortuous wormholes resulted highrer oil recovery than the straight wormholes and the oil recovery decreased as number of fratures and fracture width increased. The microgel concentration had a signicicant effect on plugging effeciecny; therefore, the 5000 PPM Microgel showed higher plugging efficiency than 2000 PPM. The result showed the interwell connectivity between the injector and producer decreased when low salinity waterflooding applied and increased the interwell connectivity between the injector and the monitoring points. The plugging efficiency, stabilized injection pressure, fracture pressure, monitoring pressure, and water residual resistance factor—all increased when the salinity of injected water decreased. Furthermore, the microgel strength decreased as brine concentration decreased. However, lower salinity water caused the incremental oil recovery factor to increase. Thus, there is a limitation in increasing the plugging efficiency under low salinity water. This limitation occurred when the brine injection pressure was less than the PPG’s extruded pressure. Combining two different EOR technologies can improve displacement and sweep efficiency and, in turn, enhance conformance control.