Core flood experiments are an integral part of the methodology for chemical selection and the optimisation of scale inhibitor treatments, providing information on formation damage, inhibitor return profile and the dynamic retention isotherm under post flush conditions (as a function of SI, brine, pH, rock matrix, T etc.). In the absence of formation damage, the comparative inhibitor returns are often used to select the chemical prior to field treatment. However, it is recognised that there can be significant discrepancies between the core data and field data, depending on how the tests are conducted and how the data are interpreted. In this paper, we describe the factors causing differences between the field and the core flood return. This includes inherent petrophysical differences between the small core plug and the larger near wellbore formation and differences in the saturation levels (e.g. core flood return typically at Sor) etc.. The paper also demonstrates that when considered appropriately, these differences should not impact the relative return profiles for different products. Other, more significant aspects however, often relate to artifacts of the core test design, e.g. oversaturation with pre-flush and main treatment solutions of which multiple pore volumes are commonly applied in core tests. This work will demonstrate that such aspects can have significant consequences for the comparative inhibitor returns and moreso that these can have considerably different impacts (order of magnitude) for different chemical treatments, especially when highly retentive products are being assessed. The result being that for ill suited test protocols, selection of less effective chemicals and poor initial treatment design can result. This paper presents examples of a series of core flood data in which the return profiles and derived isotherms show excellent agreement with field returns together with other examples were this is far from the case. We identify certain artifacts in commonly conducted core flood designs that should be avoided and recommend approaches and test protocols which allow more appropriate product ranking as well as modified modelling approaches which allow improved simulation from core to field..

Hydrochloric acid (HCl) is commonly used to remove wellbore damage and to enhance near-wellbore formation permeability in carbonate formations. Although in most cases the spent acid is recovered rapidly during well flow back after the treatment, in heterogeneous reservoirs some of the spent acid can remain trapped for long periods becoming fully saturated with CaCO 3 under downhole conditions. These reservoir-saturated spent acids then lead to scaling when eventually unloaded into the production system. This paper describes a modelling and laboratory study to replicate the system, to allow selection of inhibitors which are effective against carbonate scales in spent acid solutions containing extremely high levels of Ca 2+ /Mg 2+ , and also remain stable at elevated temperatures in the spent acids. The work also examined chemical retention and release via coreflood testing followed by field application modelling to select effective scale inhibitors (SI) which possess poor retention properties on the carbonate substrate thereby remaining present in the "spent acid". One significant challenge associated with this study was the ability to reproduce the mildly oversaturated field scaling environment in the laboratory. When using these fully saturated (with respect to CaCO 3 ) partially acidic brines, very small changes in the brine chemistry or preparation procedures had a significant impact on scaling. A detailed evaluation of brine preparation, stabilisation and buffering was therefore required prior to evaluating generic scale inhibitors for performance under these extreme conditions leading to selection of appropriate species. The second stage of the work then involved core test procedures to determine those chemicals that offered minimal retention properties on the reservoir along with performance. This paper will present the field scaling challenges observed due to unloading of trapped spent acids; describe challenges faced within the laboratory in reproducing these conditions and present results from generic chemical types which are effective at preventing scale under these extreme conditions. From the shortlisted products further results are presented demonstrating those which offer poor retention, which is generally the opposite of what is required for conventional scale inhibitor squeeze treatments, allowing selection for upcoming field trials in the selected field system.

Core flood testing of phosphonate-based scale inhibitors in reservoir sandstone containing iron minerals revealed potential formation damage caused by unmodified acid phosphonates, which are reactive toward the iron minerals. The mechanism of formation damage was shown to be due to dissolution and re-precipitation of iron phosphonate species, together with fines mobilized (also thought to be due to dissolution effects) which propagated some distance through the core, leading to pore throat blockages. In an example case, complete blockage occurred as the front of the injection chemical reached the outlet of the core due to a combination of silica fines and iron phosphonate chemical. To mitigate the potential issue, different chemical formulations were prepared based on the same phosphonate scale inhibitor, in order to mitigate / minimise the potential for in-situ dissolution of iron bearing minerals within the reservoir formation. This allowed a less aggressive formulation to be prepared by part-neutralisation of the acid phosphonate, so achieving compatibility with the core material. Thus, no formation damage was induced and retention of scale inhibitor by adsorption ensured the potential for long squeeze treatment lifetimes. The modified product has since been applied in the field and results from the laboratory qualification, chemical re-formulation and field treatments are presented in this paper. To date, 27 wells have been squeezed; the part-neutralized chemical targeted at susceptible wells and the acid chemical used elsewhere. Excellent are results in both formation damage and return lifetimes minimising the requirement for coil tubing scale removal treatments in this field.

Coreflood experiments are an integral part of the selection and optimisation of scale inhibitor treatments, providing information on formation damage, inhibitor return profiles and dynamic retention isotherms. However, significant discrepancies can arise between core and field due to test methodology. In a previous paper (SPE131131), we demonstrated that test methodology can have significant consequences for the comparative inhibitor returns, particularly with respect to oversaturation. The paper showed that many of the limitations can often be overcome through appropriate simulation techniques. We extend this work and present further results of laboratory core flood tests specifically designed to examine the effect of core flood test methodology on the derived return isotherm, particularly examining the effect of injection of different volumes of main treatment ranging from ~ 0.5 pore volume (under saturated) to 20 pore volumes (over saturated) for a series of different generic scale inhibitors. This work clearly identifies the significant detrimental artefact of inhibitor oversaturation. This paper differs from the previous works (SPE 131131) in that examples are shown where core flood oversaturation can not be overcome with effective isotherm derivation and upscaling. This is due to significant differences in the isotherms derived as a function of the level of oversaturation with main treatment chemical. This paper will also demonstrate the impact of low concentrations of impurities and or the use of chemical blends when testing with poorly designed core flood tests. Thus the paper directly addresses the procedures involved in core flooding, recommends approaches and test protocols which allow more appropriate product ranking and allow improved simulation from core to field.

This paper presents the evaluation of the effectiveness of two novel organic acid stimulation fluids for matrix acidizing of a high temperature, high CO2 gas carbonate reservoir offshore Sarawak, Malaysia. During high CO2 gas production, formation damage arising from fines migration and calcite scales may plug the near wellbore pore throats resulting in productivity impairment. Therefore, a study was conducted to investigate the effectiveness of two different stimulation recipes for matrix acidizing of a high CO2 carbonate reservoir. Core-flood tests were performed to determine the pore volume to breakthrough (PVBT) and time to breakthrough (TBT) at the various selected injection rate. Characterization and morphology studies of wormhole were done using micro CT imaging. Initial selection of stimulation fluids for matrix acidizing was based on the mineralogical composition of the main producing formation. Bottle tests were conducted whereby concentration of ion Ca2+ and weight of rock sample versus time was measured. Two stimulation fluids, products A and B were selected and core-flood test were performed at 275°F on the reservoir cores. Product A is a proprietry chemical available in the market whilst product B is an in-house developed chemical. Four different stimulation fluid injection rates (1.5, 3, 5 and 7 ml/min) were selected. Pore volume breakthrough (PVBT) and time to breakthrough (TBT) versus injection rate were evaluated and optimum injection rate for each product was determined. Wormhole length and morphology created by the stimulation fluids were visualized and determined through micro CT imaging. Mineralogy analysis of the production zone cores showed content of 70-80% calcite, 6-7% authigenic clays, 2-5% dolomite 2% plagioclase, 2% K-feldspar and 1-2% pyrite. Quartz and siderite are less than 1%. Selection of stimulation fluids was based on the mineral compositions and its dissolution rate in the bottle test. Products A and B both recorded the same optimum injection rate. Observation also showed increase in injection rate from 3ml/min to 5 and 7ml/min lead to higher consumption of stimulation fluids with no significant changes to time to breakthrough. On the contrary, reducing injection rate from 3ml/min to 1.5 ml/min lead to formation face dissolution (Product B). However, product B showed temperature instability at 275°F whereby white emulsion effluent were collected during core-flood test. Therefore, optimization of product B is required to improve its stability. Dissolution pattern for each stimulation fluid were evaluated through micro CT imaging. At 3 ml/min, ideal wormhole morphology was created for both Product A and B. This paper presents the study of two novel organic acid stimulation recipes in matrix acidizing the high CO2 carbonate reservoir. Performance and stability of each stimulation fluids at 275°F were evaluated by determining the pore volume and time to break through. The paper also present recommendations for optimum injection rates for matrix acidizing a high CO2 carbonate reservoir.