Calcium sulfate is inherently a difficult mineral scale during oil and gas production process because the amount of scale formed is much greater than that of barium sulfate at similar scale saturation index level, and it is very difficult to clean up. This is especially challenging in conjunction with HTHP stimulation treatments where compatibility of the scale control chemical with fracturing fluids is critical, and when longer-term inhibition performance is desired. A new solid inhibitor was developed for this purpose and applied in multiple wells in the Krishna Godavari (KG) basin offshore India to combat mineral scale within the proppant pack and production tubing over the long term, under extreme downhole conditions (T= 400°F, P=13,500 psi). Normally, downhole chemical injection mandrels and surface treatments cannot adequately control scale deposition under these conditions.
The new solid inhibitor product was made by adsorbing scale inhibitor onto a high-strength, proppant-sized substrate with a large surface area. The high-strength substrate were prepared by sol-gel chemistry through hydrolysis of aluminum alkoxides and formation of particles that are calcined and then sintered at high temperatures to produce a substrate with the desired strength and surface area. The scale inhibitor used exhibited excellent inhibition performance and good compatibility with metal based cross-linked fracturing fluid systems at high temperature.
Tests performed with proppants/substrates show that using high loading of the substrates with the proppant does not damage the proppant pack even under very high stresses, For example, API crush tests of a mixture of 80% conventional untra-high strength proppant with 20% substrate by weight at 13,000 psi produced less than 4.7% fines and 88% of the produced fines were larger than 100 mesh and the fracture conductivity of the pack is maintained. The results of comprehensive laboratory testing show the new solid inhibitor can prevent anhydrite scale up to 400°F, and is completely compatible with zirconium- crosslinked fracturing fluid at 350°F and above. To date, six fracture treatments have been performed using a total 23,800 lbs of this new solid inhibitor. The wellhead water samples are being collected for scale inhibitor residuals analysis, as the wells start to produce water.
To ensure compatibility of the inhibitors with high-temperature fracturing fluids, especially metal based cross-linked fracturing fluids, without compromising the inhibition longevity at high pressure and temperature remains a stiff challenge, although adding scale inhibitors to a fracturing fluid has been a well-established practice to provide long-term inhibitor protection during hydrocarbon production. The new approach described here meets this objective, extending the long-term well performance under HTHP conditions.
Shady, Mohammed (Schlumberger) | Okafor, Charles (Schlumberger) | Pazzi, Jorge (Schlumberger) | Thomas, Oluyinka (Schlumberger) | Sule, Ayuba (Schlumberger) | Ali, Ahmed Moge (Schlumberger) | Hamdane, Toufik (GSA) | Hachelaf, Houari (GSA) | Allal, Abdelhalim (GSA) | Collela, Luigi (GSA) | Latronico, Roberto (GSA) | Marfella, Ferdinando (GSA)
Berkine basin is one of the main oil producers in Algeria. The upper, middle, and lower TAG-I are the target oil-bearing sands. In this basin, the ROD field is under pressure maintained mainly through water injection together with, to a lesser extent, gas injectors. The southern part of the field, "ROD Tail" has four water injectors targeting the middle TAG-I. In recent evaluation conducted through pressure measurement and an interference test, reservoir pressure was found to have declined by 35 bar within 2 years. This has prompted questions about reservoir management, mainly about the effectiveness of injector well capacity in maintaining reservoir pressure. Extensive data were gathered through well intervention; cleanout, perforation, and a caliper log. Many failed acid jobs were also noted in the history of these wells. An engineered high-pressure jetting operation via coiled tubing was executed, but injectivity could not be restored.
A methodology and workflow were adopted to identify the source of formation damage and scale deposition in the near-well area and around perforations. Solid samples were collected from the well and sent to laboratory to characterize formation damage type. The injection water was also analyzed by performing a standard 12-ion concentration analysis. An aqueous model simulator was used to confirm that the water was supersaturated with CaSO4 and CaSO4.2H2O. Finally, clay acid treatment was found to be effective. The treatment fluid was designed to prevent proppant dissolution and to clean fracture matrix interface. This was the first time this type of operation was executed after many unsuccessful conventional acidizing operations.
Excellent results were obtained after the acid stimulation treatment. The injection rate was found to increase significantly from 120 m3/d to 360 m3/d. Water injection pressure was also found to decrease from 243 bar to 220 bar, and the injectivity index increased by three times. Near-wellbore formation damage was removed, and formation permeability recovered. The clay acid treatment was applied to other wells in the field and similar results were obtained.
Abnormal annulus behaviour is an indication of a well integrity problem. Monitoring annulus pressure trends is a method of identifying abnormal behaviour, thus highlighting potential integrity issues.
When a well is confirmed as having an annulus integrity issue one mitigating measure that may be put in place is to increase the pressure monitoring requirements associated with the well for possible escalation. It is recognized that the sooner an integrity issue is spotted the more opportunity there is to respond in an adequate manner by putting mitigating measures in place. For this reason the review of wells that do not have known integrity issues is equally important as any deviation from a normal or expected pressure trend may indicate the onset of an issue that could otherwise go unnoticed for some time.
Therefore systematically analyzing all annulus pressures from the entire well stock is a powerful tool in the well integrity management toolbox. Carrying out the generation of annulus pressure plots for performing these analyses can be a laborious and time-consuming task, especially when the well stock contains more than say 50 or 100 wells. Therefore to carry out systematic reviews of all wells can a challenge.
To aid in overcoming this challenge a tool was developed to automate the generation of annulus pressure trends, either by selected well or by selected asset. For each well a set of three plots is generated as standard. Each plot has a time axis and a pressure / temperature axis with scales that can easily be modified to zoom in for a detailed picture or to zoom out to get a good overview.
Implementation of the tool has resulted in an increased surveillance of the annulus pressure trends. Depending on the asset, weekly or even daily reviews of all wells are now done. As a result the understanding of the integrity status of the entire well stock has increased considerably. New well integrity issues that result in a change in annulus behaviour are now detected much earlier than before. It has also resulted in the discovery of some integrity anomalies that were previously not recognized as such.
Joint inversion of PP and PS reflection data has been hindered by the difficult task of registration or correlation of PP and PS events. It can perhaps be achieved by registering the events during inversion but the resulting algorithm is generally computationally intensive. In this paper, we propose a stochastic inversion of PP and PS data which have been registered to the same PP time scale using a new interval velocity analysis technique. The prestack PP and PS wave joint stochastic inversion is achieved by using the PP and PS wave angle gathers using a very fast simulated annealing (VFSA) algorithm. The objective function attempts to match both PP and PS data; the starting models are drawn from fractional Gaussian distribution constructed from interpolated well logs. The proposed method has been applied to synthetic and real data; the inverted results from synthetic data inversion compare very well with model data, and inverted results for real data inversion are consistent with seismic data and log data. These also show that the proposed method has a higher accuracy for estimating rock physics parameters while it circumvents the horizon registration problem in the data interpretation. We also estimate uncertainty in our estimated results from multiple VFSA derived models.
One of the major problems facing oilfield operations is the occurrence of scale. In oilfields the mixture of produced water and formation water is unavoidable as produced water can be used to enhance production through water re-injection. The occurrence of scale in oil wells may cause flow restriction resulting in production damage, emergency shutdowns, increased maintenance costs due to frequent work-overs and an overall decrease in the production efficiency.
Formation water from field XYZ in the Niger Delta region was analyzed to predict the scaling tendency of the water using the General Solubility Index for Calcium carbonate. A scaling program Scale-Check© was written based on the Stiff-Davis predictive model, Langelier's predictive model and the General Solubility Index; these helped to calculate the scaling Index. Scale-Check© was used to predict the scale formation tendency of calcium carbonate scale for Well XY over three periods within the life of the well. Sensitivity analysis that showed the effect of temperature and pressure on carbonate scaling was also implemented.
Scale-Check© presents an easy-to-use program for checking the scaling tendency of formation or produced water and hence putting in place pro-active measures that go a long way to reduce the negative effects of scaling in the oilfield.
Jiecheng, Cheng (Daqing Oilfield Co. Ltd.) | Wanfu, Zhou (Daqing Oilfield Co. Ltd.) | Yusheng, Zhang (Daqing Oilfield Co. Ltd.) | Xu, Guangtian (Daqing Oilfield Co. Ltd.) | Ren, Chengfeng (Daqing Oilfield Co. Ltd.) | Zhangang, Peng (Daqing Oilfield Co. Ltd.) | Bai, Wenguang (Daqing Oilfield Co. Ltd.) | Zongyu, Zhang (Daqing Oilfield Co. Ltd.) | Xin, Wang (Daqing Oilfield Co. Ltd.) | Fu, Hairong (Daqing Oilfield Co. Ltd.) | Qingguo, Wang (Daqing Oilfield Co. Ltd.) | Xianxiao, Kong (Daqing Oilfield Co. Ltd.) | Lei, Shi
ASP flooding in Daqing oilfield commenced from 1980s. To date, industrial pilot tests have been carried out in three blocks. The averaged recovery was increased by 20%. On the other hand, scaling issue caused high frequent pump failures. Large amount of scale building up in the producers wellbore and downhole equipments with high speed, which resulted in the averaged running life of lifting system decreased from 599 days of water flooding period to 60 days. Further more, some producers' running lives were only around 30 days, leading to higher production cost and lower production rate as well.
Study indicated that, the scaling principle and scale composition in producing wells differed from each other and was difficult to be predicted accurately. In this study, after tracking and measuring the ion in produced fluid for the whole process from water flooding, polymer flooding to ASP flooding and analyzing composition of the scale on different parts of scaling well, the criterion and distinguishing chart of scaling tendency had been set up initially. The criteria were applied in 102 wells in ASP flooding area, the accordance rate was more than 90 percent. Based on that, scaling inhibition technology was timely performed for predicted scaling wells, and the running lives were increased from 40 days to above 200 days. This paper presented the process of the study and is greatly helpful for APS flooding in commercial scale.
Increasing demand of oil and gas worldwide is promoting a new, fast growth in the oil industry where the presence of experienced engineers is limited. Exploration for hydrocarbons is reaching limiting frontiers and the near future and long term challenge will be to maximize recovery from the existing fields. Enhanced oil recovery offers an alternative to improve recovery by means of introducing an external agent which enhances oil sweeping at a pore level scale.
While the EOR concept is not new; field implementation has been scarce. As a consequence the physics governing the displacement processes have not been completely understood, posing a challenge for the design and modeling of the process. This is enhanced when dealing with numerical models, which, typically are designed for primary and/or secondary depletion processes, with grid orientations and dimensions suitable for these field conditions. Very often though, these same models are used to design and evaluate the potential for field EOR. This paper addresses the main challenges of modeling the fine scale displacement mechanism with a full field model, highlighting the typical errors in recovery efficiency that can occur and suggesting scales at which screening models can be built.
Displacement processes in the reservoir are dominated by the combination of the viscous and capillary forces, the efficiency and ultimately the amount of displaced oil is controlled by the balance of these forces. During a core scale displacement process, viscous forces are dominant and most of the oil is contacted by the injected agent. This displacing mechanism is different from the one experienced at reservoir conditions where gravity forces play an important role, influencing the amount of oil which is contacted by the EOR agent, where under and over-running may occur. Modeling of these displacements requires a greater resolution than the one used in for the full field model. The impact of model size and force balance during an EOR displacement process is presented is this paper.
Yang, Yonghua (China University of Petroleum, Beijing) | Zhou, Wanfu (Daqing Oilfield Co., Ltd) | Shi, Guochen (Inst of Daqing Oil Prod Tech) | Gang, Cao (Daqing Oilfield Co. Ltd.) | Wang, Guoqing (Daqing Oilfield Co. Ltd.) | Sun, Chunlong (Daqing Oilfield Co. Ltd.) | Qiang, Li (Daqing Oilfield Co. Ltd.) | Zhao, Yunlong (Daqing Oilfield Co. Ltd.) | Zhao, Changming (PetroChina Daqing Tamtsag, LLC) | Bai, Wenguang (Daqing Oilfield Co. Ltd.) | Wu, Miao (Daqing Oilfield Co. Ltd.) | Li, Yanfei | Zhang, Ming | Li, Jinling | Ma, Zhiquan | Xu, Wenlin
To date, ASP flooding has been applied in commercial test in Daqing Oilfield for 17 years. From the beginning of the test, scaling issue in downhole artificial lift equipments had been realized as one of the most difficult problems in ASP flooding which resulted in high pump failure rate and operation cost. Therefore, the scaling principle in producers was studied in order to create a scaling risk analysis and risk prediction mechanism. In addition, Based on numerous laboratory study and field trial, a series of anti-scaling artificial lift techniques were developed as well, including surface material modification technique, special pump design, chemical scaling remover, etc.
Due to the considerable diversity of scaling phenomena in different blocks, different period and different wells, the antiscaling artificial lift strategy was required to be adjusted respectively. Consequently, an innovative anti-scaling artificial lift methodology was created for different ASP flooding areas in Daqing Oilfield. This methodology was applied in 102 wells, both in beam pumping wells and PCP wells. The averaged running lives of artificial lift systems were improved from less
than 30 days to over 300 days.
This paper detailed the developments of innovative artificial lift technology in ASP flooding in Daqing Oilfield. These new developments will effectively propel the commercial application of ASP flooding in petroleum industry.
Alkaline Surfactant Polymer (ASP) is a novel EOR technique developed from the end of last century. It combines the advantages of surfactant flooding and polymer flooding which could improve the recovery rate and sweeping volume. Moreover, ASP flooding can reduce the developing cost considerably due to much less quantity of surfactant. From 1990s, Daqing Oilfield began to study the mechanism of ASP flooding. Both several hundred of surfactant formulas and different
molecule quantity polymer were tested in order to get proper ASP system formulas matching for different blocks. Based on numerous theoretic study and experiments, 6 ASP flooding pilot tests commenced from 1994 to 2004. Based on water flooding development, the recovery rate was 19.4 to 25 per cent by ASP flooding. Till 2010, 6 another ASP flooding pilot tests had been carried out in Daqing Oilfield. The recovery rate was 18.1 to 25 per cent higher than water flooding.
However, scaling issue in artificial lift equipments was a bottleneck problem for ASP flooding. In the process of producing in ASP flooding, ASP fluid reacted with rocks in the reservoir resulting to a small part of rocks solute. When the producing fluid enters the well bore, large quantity of scaling deposited on the surface of production equipments, including casing, tubing, pump, and sucker rods. See Figure 1, 2. Severe scaling issue resulted to high failing rate of artificial lift system as
well as fast increment of developing cost. In the scaling stage of ASP flooding, the averaged running life of PCP is only 47 days. As for beam pumping wells, it was less than a month. Scaling issue of artificial lift systems limited the development of ASP flooding considerably. In that case, Daqing Oilfield began to develop anti-scaling PCP technique, scale control beam pump and chemical scale removing techniques.
At the conclusion of flooding an oil- or gas-bearing reservoir, a significant fraction of the original hydrocarbon in place remains trapped. In addition to determining the amount of residual phase, knowledge of its microscopic distribution within the rock pore space would allow a better understanding of recovery mechanisms, and the design and implementation of improved or enhanced recovery processes. While the importance of the pore scale structure, mineralogy and wettability in dictating the residual phase distribution is widely acknowledged, little quantitative information on these properties and dependencies has been directly available. To this end, we describe an ongoing interdisciplinary study, bridging the core-, pore- and molecular scales using x-ray microtomographic imaging, petrographical imaging and wettability imaging. The experimental techniques used are reviewed, emphasizing the registration technology which enables spatial alignment and integration of 2D SEM-based information with 3D µ-CT images. Application of these techniques to visualization of pore scale oil and brine populations is presented, with a particular focus on characterizing native state carbonate plugs. In parallel, direct visualization of the alteration of rock surface chemistry at the pore- and molecular scales due to oil exposure is presented for macroporous and microporous reservoir carbonates. This interdisciplinary approach provides the foundation for more systematic development of strategies to increase recovery, in particular by tuning wettability.
The amount of residual hydrocarbon phase in a reservoir rock after flooding has obvious importance in determining the completeness of secondary recovery and the target for tertiary recovery. Further knowledge of the distribution of this trapped phase within the rock pore space would facilitate a more transparent and systematic approach to improved or enhanced recovery. In flooding experiments on reservoir core material, the core scale distribution of residual can be quantified (e.g. by magnetic resonance imaging or computerized tomography), however deeper insight into its configurations at the pore scale is necessary to better understand the underlying displacement mechanisms. Most methods previously pursued to characterize the residual oil phase at the pore scale use either idealized 2D micromodels (Lenormand et al. 1983) or destructive techniques on model liquids in rock (pore/blob casts) (Chatzis et al. 1983). The observations from these studies helped to ascribe rules for meniscus advance through connected pores in simple network models of multiphase flow. The enormous advances in x-ray micro-computerized tomography (µ-CT) over the past decade have greatly increased the scope for imaging rock pores and calculating properties from the digitized 3D images. This has allowed network models to more realistically incorporate the geometry and topology of pores in rock cores. However, the corresponding characterization of mineralogy and wettability to specify the pore scale distribution of molecular-scale surface chemistry adorning the pore walls is lacking, and thus the pertinent contact angles to be used in modeling are not known. Further, the ability to 3D visualize with µ-CT the residual phase occupancy in individual pores of rock cores is required to test the predictive power of such models and guide any augmentation of the mechanisms of pore displacement in real rocks to obtain better agreement.
Coli, N. (Department of Civil, Environmental and Material Engineering (DICAM), University of Bologna) | Berry, P. (Department of Civil, Environmental and Material Engineering (DICAM), University of Bologna) | Bruno, R. (Department of Civil, Environmental and Material Engineering (DICAM), University of Bologna) | Boldini, D. (Department of Civil, Environmental and Material Engineering (DICAM), University of Bologna)
Bimrocks are structurally complex formations made up by a fine-grained matrix including heterometric hard-rock fragments which deeply influence their mechanical behavior. A new approach for characterizing the morphological and spatial variability of rock fragments in bimrocks is introduced, based on the geostatistical analysis of bimrock outcrop pictures through a single-scale variogram analysis of the rock fragment indicator variable IB (x, y). The analysis indicated the presence, all over the field, of a nested structure characterized by three or four common elementary variogram models, each taking into account the variability of a specific size range of the rock fragments. A first attempt was also made in order to investigate the possible correlations between the bimrock strength parameters, obtained through in-situ non-conventional shear tests (BimTests), and the geostatistical indexes, which quantify specific spatial and morphological properties of the fragments, by means of a Cross- Covariance study of non-isotopic regionalized variables (ReV).
Bimrocks  are structurally complex formations characterized by a fine-grained soil, the “matrix”, which includes, in a typical block-in-matrix fabric, hard-rock fragments of variable dimensions. The presence of rock fragments above a critical threshold size, namely the block/matrix (B/M) threshold, deeply influences the mechanical behaviour of bimrocks [2, 3, 4, 5, 6, 7]. The B/M is not an absolute property of bimrocks but is related to a specific engineering scale of interest (i.e. several B/M can be identified depending on the working scale of the problem under investigation). Due to their complex structure, an exhaustive mechanical characterization of bimrocks requires some special investigations to be carried out. In particular a nonconventional in-situ large size test (namely BimTest) was developed by the Authors in order to properly take into account the presence of rock fragments and their interactions with the soil matrix . The main advantage of BimTest is that that the shear plane is free to develop inside the specimen, thus allowing for an increase in tortuosity of the shear plane, leading to an increase in the bimrock shear strength compared to that of the only clayey matrix. However, the in-situ characterization through BimTests could result in a quite expensive and time-consuming task, especially when large volumes of the formation are involved. For this reason, the possibility to integrate the mechanical tests with an indirect method of characterization was investigated. The analysis aimed at correlating the strength parameters with 2D geostatistical indexes obtained through a single-scale variogram analysis of the rock fragment indicator variable IB (x, y), performed on digital pictures of outcrop exposures. The present study was carried out on a wide slope located in a dismissed open-pit mine in Tuscany, Italy, characterized by a wide exposure (about 345.000 m2) of an Oligo-Miocenic olistostrome of the Tuscan Nappe. The formation is constituted by a dark-grey clayey matrix containing rock fragments of micritic and arenitic limestone  (Fig. 1).
2. THE BIMTEST
Six BimTests were performed over the investigated area, on specimens of 0.3 m3 (80x80x50 cm) .