Contribution from Laboratory to Field: Case Studies of Asphaltene

Article pubs.acs.org/EF

Contribution from Laboratory to Field: Case Studies of Asphaltene Precipitation Risk Evaluation Hideharu Yonebayashi,*,† Daisuke Urasaki,‡ and Takaaki Uetani† †

Technical Research Center, INPEX Corporation, 9-23-30 Kitakarasuyama, Setagaya-ku, Tokyo 157-0061, Japan Eurasia & Middle East Project Division, INPEX Corporation, 5-3-1 Akasaka, Minato-ku, Tokyo 107-6332, Japan

‡

ABSTRACT: Three case studies pertaining to the precipitation risk of asphaltene, which comprise comprehensive evaluation from laboratory measurement to practical feedback into the field, are described. Two cases included aspects of gas injection, and the third corresponds to formation damage at a naturally depleted field. Asphaltene onset pressure (AOP) is a fundamental characteristic that represents in situ asphaltene behavior from a single-phase fluid sample; therefore, all evaluations were performed on the basis of laboratory-measured AOP data. The evaluations reported reveal how practical interpretation of laboratory-measured AOPs links appropriately to actual on-site phenomena. In the first two case studies, numerical asphaltene fluid models, calibrated using measured AOPs, were generated to evaluate asphaltene precipitation envelopes (APEs) by applying the cubic plus association equation of state. In the first case, a sensitivity analysis based on a numerical model of the original reservoir fluid was performed for several injection gases to investigate the impact of gas injection on APE behavior from the subsurface and surface points of view. In the second study, the variation of asphaltene deposits, actually observed at the gas injection pilot area, was explained by considering the vaporizing gas drive (VGD) process in terms of APE behavior. A sensitivity study was conducted to estimate how enriching the injection gas by this effect could expand the APE. An expanded APE could cause the variation of asphaltene deposits observed in the field: deposits were observed at certain times when enriched injection gas was accumulated but not when lean injection gas accumulated. Control of pressure depletion is considered an effective countermeasure to mitigate asphaltene precipitation in a naturally depleted field. For a field with a potential asphaltene deposition problem in the reservoir, it is recommended to maintain the reservoir pressure above the AOP. Such mitigation needs reliable AOP data. Once destabilized, solid particles of asphaltene grow continuously from the nanoscale (precipitation) to the microscale by aggregation. Our AOP measurements adopted the latest laboratory techniques. Three data sets were acquired using filtration, high-pressure microscopy analysis, and laser light scattering techniques. Despite using the same single-fluid sample, the AOP results were not identical because each measuring technique had different detection limits for the minimum asphaltene particle size. This paper demonstrates how we assessed the AOP data to determine the cause of asphaltene-induced formation damage by comparison to actual flowing bottomhole pressure behavior. This practical AOP measurement could suggest a more optimum pressure control target that would allow for maximum oil production while mitigating production potential loss as a result of shutdown for cleanup or removal jobs.

1. INTRODUCTION Gas injection is globally applied as one of the promising enhanced oil recovery (EOR) options; however, it is wellknown that gas addition to reservoir fluid often causes asphaltene precipitation. This can result in formation damage, a decrease in oil production as a result of the tubing plug, an increase in the operating cost associated with more frequent removal of asphaltene deposits, deterioration of separation efficiency as a result of asphaltene emulsions, and shutdown of facilities to remove asphaltene sludge. The risk of asphaltene precipitation must therefore be carefully evaluated before applying gas injection. Pre-evaluation of asphaltene is now becoming a regular component of gas injection studies. 1.1. Asphaltene Risk in Gas Injection. Asphaltene flow assurance is becoming increasingly important because of the increasing number of gas injection projects planned. Among possible types of gases, the use of CO2 injection is currently most favored not only for improving oil production in mature fields but also for storage of CO2 in in situ reservoirs. This motivation follows from the industrial pursuit of CO2 capturing technology that can comply with the recent strict environ© XXXX American Chemical Society

mental requirements. Actual oil production using CO2 EOR requires a sustainable CO2 supply that cannot be maintained by a natural source alone. Carbon capture storage (CCS) is therefore combined with CO2 EOR. Figure 1 shows the CO2 EOR history for the past 30 years in the United States.1 The contribution of CO2 EOR had achieved 284 kilobarrels of daily oil production by 2012. Except for a short period around 2002, there has been a continuous upward trend in enhanced oil production. The U.S. Department of Energy’s National Energy Technology Laboratory (DOE/NETL) has developed a growth forecast for sourcing CO2 that includes remaining CO2 natural source reserves and CO2 captured from artificial resources.1 As a result of this increasing CO2 supply estimation, the growth of CO2 EOR oil production is predicted to be sustainable during the period from 2012 to 2018, as Special Issue: 17th International Conference on Petroleum Phase Behavior and Fouling Received: August 25, 2016 Revised: October 21, 2016

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DOI: 10.1021/acs.energyfuels.6b02152 Energy Fuels XXXX, XXX, XXX−XXX

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Table 1. History of AOP Measurement Techniques Applied Since the 1990s reference

technique applied to detect asphaltene onset

13−16 2, 15, and 17−20 21 and 22 15, 16, and 23 24 and 25 3, 5, 8−10, 15, 19, 20, and 26−41 23 and 42−51

ARTa filtration refractometer gravimetric capillary pressure or viscosity (capillary flow) LSTb LST with visual method

a

ART = Acoustic resonance technique. bLST = Laser light scattering technique.

the laser light scattering technique (LST). A high-pressure microscope (HPM) can be equipped with the LST apparatus for visual observation. The minimum asphaltene particle sizes that can be uniquely detected depend upon the AOP measuring technique. Because asphaltene particle growth is continuous, in general, the occurrence of asphaltene operational troubles is not simultaneous with the start of precipitation. In particular, this fact is crucial for optimum pressure control in a naturally depleting field that is experiencing asphaltene-induced formation damage. In other words, from available AOPs measured by different techniques, it is important to narrow down the actual AOP value at which problems can start.

Figure 1. United States oil production from CO2 EOR.

shown in Figure 2.1 The increase in asphaltene risks by gas injection has been widely recognized.2−12 It is therefore

2. MATERIALS AND METHODS 2.1. Reservoir Fluid and Asphaltene. While asphaltene precipitation is generally theoretically considered a reversible process, the reality at site is often different. To preserve original fluid information as far as possible, single-phase bottomhole samples were therefore used in all case studies. The characteristics of the reservoir fluid and asphaltene are summarized in Table 2.

3. CASE STUDY 1 3.1. Background and Motivation. Production tubing in an offshore carbonate field has experienced asphaltene deposition. Problematic wells occur especially in the upper of two main reservoirs, while lower reservoir producers have not encountered any particular asphaltene problems. Asphaltene deposits in tubing have been treated using mechanical, chemical, and/or operational approaches, such as use of a running gauge cutter, xylene soaking, minimizing drawdown by horizontal well drilling, and maintaining pressure by gas and water injection. The application of downhole asphaltene inhibitor squeezing52−55,17 was attempted to delay asphaltene deposition in the tubing and to reduce the frequency of removal operations; however, this treatment was suspended because of insufficient response caused by inadequate adsorption of the squeezed inhibitor on the carbonate rock surface, which reduces the retention time of the effectiveness of the inhibitor to below expectation. The more conventional remedy of continuous downhole inhibitor injection2,5,56,57 was not considered a viable option because the large capital investment required workover to introduce macaroni injection lines into dual completed wells. Despite a long history of tackling the asphaltene problem, it has not yet been remedied. This field has development plans to apply gas injection for EOR. This case study therefore mainly focused on a preparatory risk evaluation of asphaltene-precipitating behavior under gas-mixing conditions.20 It was important to minimize its

Figure 2. Forecast for United States incremental oil production and purchased CO2 requirements from CO2 EOR (2012−2018).

expected that future requirements to evaluate asphaltene flow assurance for gas injection projects will increase. 1.2. Asphaltene Onset Pressure (AOP) Detection Techniques. For asphaltene risk evaluation using numerical models, the most important experimental data are that of AOP, which are used to calibrate the models. This experimental information is a key parameter to ensure the model validity. For more accurate measurement of asphaltene onset conditions, techniques have been constantly developed and improved, as shown in Table 1. Unsophisticated approaches, such as filtration and gravimetric methods, were applied in the 1990s but are still sometimes used in the 2010s. These two methods are widely applicable to any kind of oil but are labor-intensive. More convenient approaches, such as acoustic resonance technique (ART), refractometer, and capillary pressure/ viscosity measurement, were tried but have not had major success thus far. Currently, the most widely applied method is B


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Energy & Fuels Table 2. Summary of Fluid Characteristics: Compositions and Asphaltene Onset Pressure

Average of four fluid samples collected from another well in the same reservoir. bData taken by means of IP-143. cAOP was measured under natural depletion condition. dAOP was measured under gas injection condition at 50mol% gas added. a

Figure 3. Workflow for case study 1.

first campaign, and LST was used in later campaigns. AOPs were measured under conditions of both natural depletion and gas injection. With calibration using AOP data for natural depletion, a numerical model was generated using the cubic plus association equation of state (CPA EoS) for the well A single-phase bottomhole sample collected from a reservoir experiencing asphaltene (see the dotted line in Figure 4). Upon objectively reviewing all pressure−volume−temperature (PVT)

risks and to optimize the gas injection plan. It is also worth noting that the field was historically subjected to lean gas injection without any observation of additional asphaltene deposition. The study workflow is described in Figure 3. 3.2. Numerical Modeling of Calibrated Experimental Findings. During the long history of field work, the latest techniques were adopted for the AOP measurement for each fluid analysis campaign. The filtration technique was used in the C


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The results are summarized in Figure 6. For validation purposes, those expanded APEs were compared to experimental AOPs measured from gas titration tests using the associated gas. This comparison showed good agreement. Asphaltene precipitation risks were evaluated separately for several location: the surface facility, production tubing, and in situ reservoir. The analysis was based on the magnitude of APE expansion and the relationship between operating condition and all APEs on thermodynamic plots. Evaluation of locationdependent risks was considered necessary because the asphaltene problematic location has been specific to tubing in some producers. At the surface facility, the associated gas (lowest C1 content = 40 mol %) was considered more risky than other gases because part of the current surface operating condition was intersected by expanded APEs. This was most likely affected by the higher concentrations of C2 and C3 in associated gas than in the other gases; however, its gas risks could be mitigated by a full-field development plan (FFDP) that will move the operating condition away from APEs. As a remarkable observation of APE behavior, natural gas showed the unique trend that APE was deviating away from the operating condition, even though the APE expanded. Because the saturation pressure line moved more than the lower boundary expansion of the APE, the asphaltene precipitation risks decreased by adding natural gas. While the extent of risk at the surface facility depended upon the type of injection gas, all injection gases accelerated asphaltene precipitation risks and resulted in an increase in coverage of the pressure−temperature (P−T) tubing line by expanded APEs. Risks at the in situ reservoir also depended upon injection gas type. The lowest magnitude of APE expansion was observed for associated gas; expansion was higher for mixed gas but still lower than that of natural gas. Injection of natural gas showed the highest risks for the reservoir and tubing; however, no deterioration of gas injectivity and/or permeability was reported during a previous period of actual natural gas injection (1988−2000). Asphaltene-induced formation damage was therefore not considered severe and occurred at an undetectable level, even though asphaltene did precipitate. 3.3. Summary. (1) Location-dependent asphaltene precipitation risks were summarized as follows. (a) At in situ reservoir: Although asphaltene precipitation risk was predicted to increase for all gas injection cases, formation damage was not severe according to historical observation during natural gas injection (highest risk of three gas types evaluated) in this field. (b) In tubing: Risk was observed to increase with gas injection. More effective counteraction might be required. (c) At surface facility: Little risk was observed on the basis of gas mixing sensitivity studies. The implementation of a FFDP would lower wellhead flowing pressure and improve robustness from a risk management point of view. (2) If the asphaltene precipitation risk was not effectively remediated at upstream locations above the surface facility (i.e., in tubing and reservoir), asphaltene deposits that occurred in those locations might cause problems in the surface facilities. It was recommended to prepare adequate space for a chemical injection pump to be installed as a remedy for such a situation. In addition, the capability and feasibility of installing a chemical injection pump should be checked, including issues such as adequate electrical supply.

Figure 4. Prediction of baseline APE for well A fluid.

data, however, a unique anomaly was observed in the light hydrocarbon (C1) contents. The baseline model was therefore modified by taking this anomaly composition into account. The anomaly C1 content in the well A fluid model was adjusted to the average value by proportionally recalculating the contents of the remaining composition, so that total contents remained at 100 mol %. The final adjusted asphaltene precipitation envelope (APE) is shown as the thick line in Figure 3 and provides the baseline APE for case study 1. The subsequent sensitivity analysis was performed assuming future gas injection on the basis of this baseline APE. Three injection gases were examined in the sensitivity analysis, of which their compositions are shown in Figure 5: (1)

Figure 5. Compositions of injection gases tested in sensitivity analyses.

natural gas, with the highest C1 content, (2) associated gas, which is the richest (i.e., has the highest C2 and C3 contents), and (3) a mixture that has intermediate characteristics between those of natural and associated gas. It was investigated how the baseline APE expanded by adding injection gas. D


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Figure 6. Gas mixing sensitivity for asphaltene risk evaluation for different injection gases.

4. CASE STUDY 2 4.1. Background and Motivation. The target field has produced light oil from carbonate reservoirs for more than 45 years. To maintain reservoir pressure, dump floodwater was applied, followed by powered water injection. Crestal gas injection was started some 10 years ago. In addition, a new gas injection pilot (GIP) project has been carried out in part of the flank area of the field. The first asphaltene deposits were observed in October 2007 from well B that is located 1.5 km south of the gas injector well C in the GIP area. After the first field observation of asphaltene deposition, an immediate remedial response was taken by the operator in 2008. This consisted of a fundamental asphaltene laboratory study that included saturate, aromatic, resin, and asphaltene (SARA) analysis and AOP measurement. The single-phase bottomhole sample in well D was used for the study because it best satisfied relevant criteria (such as being as newly collected as possible, close to the GIP area, and not yet

mixed with injection gas). AOP was detected for a mixture of well D reservoir fluid and 50 mol % injection gas added in an isothermal depressurizing test; no AOPs were detected for mixtures with lesser amounts of gas added (ranging from 0 to 43.75 mol %). On the basis of these experimental findings, a numerical fluid model was generated by Yonebayashi et al.58 for the well D fluid to evaluate APE by applying the CPA EoS: commercial software Multiflash version 3.659−61 was employed. The study workflow is described in Figure 7. As shown in Figure 8, the AOP-calibrated model was initially generated as the baseline. This calibration was performed using the unique AOP detected in case of 50 mol % injection gas added. Possible APEs were also developed for other mixtures by adjusting the injection gas concentration of the baseline model to each value: 0−43.75 mol % added. All APEs were comprehensively considered to mimic gas mixing during the continuous gas injection process; however, none of the APEs E


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Figure 7. Workflow for case study 2.

Figure 8. Baseline APE calibrated by AOP and possible APEs.

was located on the in situ producing condition in P−T plots. This was contradictory to the fact that actual asphaltene deposits were observed from well B. This contradiction provided strong motivation for the study, and further mechanisms were incorporated into the APE investigation. 4.2. Vaporizing Gas Drive. Slim tube tests using well D fluid and injection gas showed that the minimum miscibility pressure (MMP) was close to the reservoir pressure but lower than the injection pressure. Under the conditions, two types of driving processes can be expected, depending upon reservoir location: a miscible drive, possibly near the gas injection well, and an immiscible drive, far from the gas injection well. In the miscible process, multi-contact miscibility by vaporizing gas drive (VGD) can be near the injector location and first-contact miscibility can be at a closer location, such as near the wellbore.

Generally speaking, the injection gas is enriched as it contacts the intermediate molecular mass hydrocarbons in the reservoir oil. This enrichment can achieve miscibility more easily via the VGD process that is illustrated in Figure 9. Reservoir oil D containing intermediate molecular mass hydrocarbons lies on the extension of the limiting tie line through the plait point. Injection gas and reservoir oil are not initially miscible. The injection gas therefore initially displaces oil immiscibly away from the well bore but leaves some oil behind the gas front. It is supposed that an overall composition M1 is generated from relative proportions of injection gas and undisplaced oil after this first contact. According to the tie line passing through M1, liquid L1 and gas G1 are in equilibrium at this point in the reservoir. Subsequently, gas injection into the reservoir pushes equilibrium gas G1, which remains after the first contact. G1 contacts fresh reservoir oil, and liquid L1 is left behind as residual saturation. As a result of this second contact, a new F


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original injection gas, the intermediate hydrocarbons were varied between those two dotted lines. On the basis of the baseline model (well D fluid), three enriched gases were examined to evaluate their effects on the APE (see Figure 11). As more enriched gas mixed with the

Figure 9. Schematic of the VGD process.

overall composition M2 is reached with corresponding equilibrium gas G2 and liquid L2. Further injection causes G2 to flow ahead and contact fresh reservoir oil. Repetition of this process results in progressively altering the gas composition at the displacing front along the dew point curve until it reaches the plait point composition. Practically in a reservoir, the VGD process can occur for an actual mixture of reservoir fluid and injected gas. The composition of the mixture is therefore considered to change more dynamically. AOP measurement experiments could cover the mixture compositions (well D reservoir fluid and the 0−50 mol % injection gas added) on the unique line (red line) between reservoir oil D and the injection gas in Figure 9 while ignoring subsequent lines of the VGD process, such as the green lines between reservoir oil D and G1, G2, G3, ..., Gn. 4.3. APE Estimation Incorporating VGD. To incorporate the VGD process into case study 2, three enriched injection gas compositions were considered to cover the continuous process of enrichment. The original composition of intermediate hydrocarbons (C3−C6) in the injection gas was gradually assumed to increase, becoming similar to the compositional proportions of reservoir fluid. The remaining components were maintained, followed by normalization. In Figure 10, the original injection gas composition is shown as the black dotted line and the intermediate composition of the reservoir fluid is shown as the red dotted line. While almost maintaining the same compositions of H2S, CO2, N2, and C1−C2 as those of the

Figure 11. Effect of the VGD process on the baseline APE (mixture with 50 mol % injection gas).

reservoir fluid, the APE expanded downward (lower pressure side). This trend supported observations of actual asphaltene deposition in the GIP area. This APE expansion trend by the VGD included shifting the APE into the GIP area. As a result, the actual observation of asphaltene deposits can be thermodynamically explained, as shown in Figure 12. The bottomhole condition is now within the APE shifting areas, although it is located on the P−T plot around a transitional zone of APE shifting areas before and after being affected by the VGD process. This situation can allow for observing asphaltene precipitation during a limited time period, which may depend strongly upon the condition of the enriched gas. 4.4. Validation of the APE Shifting Area in the GIP Area. To validate the VGD-affected APE shifting area, production monitoring work was recalled to investigate consistency with periodical gas sweep progress, as shown in Figure 13. Well F is located on the extension line between well C (gas injector) and well B (asphaltene observed well). At the time that the first asphaltene deposit was observed at well B in 2007, enriched gas was considered to be accumulating around well B because the injection gas reached well F in 2008. This was one piece of evidence consistent with VGD-affected APE behavior because the events occurred in a time-sequential manner: the closer injector well B showed asphaltene deposit, followed by gas breakthrough observed near well F. Further evidence was found from the history of well E. Clear gas breakthrough was observed at well E in 2005, although no asphaltene issue was reported from this well in 2008. Because 3

Figure 10. Assumption of enriched gas compositions for case study 2. G


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(various injection gas mixing ratios) under several assumptions. In addition to considering all APEs, the VGD process was incorporated into the numerical modeling interpretation to more practically estimate asphaltene precipitation behavior. (1) Field observations showed two apparently inconsistent facts: asphaltene deposits were observed in well B but not in well E in the GIP area. This variation was explained by modeling analyses incorporating the VGD process. (2) The modeling analyses showed that the APE could be expanding as the injection gas was being enriched by the VGD process. The bottomhole operating condition of GIP production wells moved into the APE-shifting area with enrichment of injection gas, although it was originally out of this area. A high asphaltene precipitation risk was identified during accumulation of enriched injection gas near the timing of gas breakthrough. After gas breakthrough, the accumulated gas around production wells returned to its original injection gas composition and the risk of asphaltene precipitation was reduced. (3) Experimental AOP measurements represented a static assessment, even assuming various gas mixing ratios, because it used at fixed gas composition. On the basis of these experimental results, their simple interpretation could not capture the true asphaltene precipitating risk for a gas injection project. Dynamic asphaltene precipitating behavior should be investigated by considering compositional changes of the injection gas.

Figure 12. Bottomhole condition could be covered by VGD-affected APE shifted area in the GIP area.

5. CASE STUDY 3 5.1. Background and Motivation. The target field has produced light oil in a domestic onshore. The first asphaltene deposits were observed in well G when production commenced. These caused formation damage, and then the oil production rate has since been controlled to mitigate the problem, even though there is higher production potential from the reservoir. This production control was an effective countermeasure; however, it was still required to frequently remove asphaltene deposits. To optimize the frequency of removal while maximizing oil production, AOPs were measured and used to achieve better production control. However, AOPs detected by various techniques were not identical and varied, as shown in Table 3. All of these results were considered correct Table 3. Measurement Results for AOP Using Various Techniques

Figure 13. Estimation of the gas sweep area progress for validation of the VGD-affected APE shifting area.

AOP result

3300−4000 psig

filtration method HPM

3410 psia

LST

5300 psig ≈ Pi

years had passed since the first gas breakthrough, the gas compositions around well E were considered close to the original injection gas compositions by sufficient flood out. These lean gas compositions could not sufficiently expand APE to cover the well E bottomhole condition. These comprehensive field observations were considered to support the findings of the numerical model. Expansion or shrinkage of the APE shifting area in the dynamic process of VGD could explain both facts concerning well B and well E. Considering dynamic asphaltene behavior, its precipitation risk would vary during the continuous displacement process of a gas injection scheme. The risk would be at its maximum near the gas front and decrease as this is swept out. 4.5. Summary. From the baseline APE model that was generated by calibrating with the unique AOP measured for the mixture of well D reservoir fluid and 50 mol % injection gas added, possible APEs were estimated for other mixtures

laboratory technique

detectable size 0.5 μm as per filter size 1.49 μm/pixel as per image processing capability depends upon fluid characteristics

with respect to the minimum detectable size of each technique and, therefore, represented real pressure points that could be initially detected by each apparatus. Precipitation was considered to start at 5300 psig according to the filtration method, which had the smallest detectable size of the three methods. Assuming that an asphaltene particle grows continuously, it was consistent that HPM detection followed that of filtration. Detection by LST placed on the lower pressure side of the HPM detecting range indicated that the LST detectable size might be slightly larger than that of the HPM. In this case study 3, engineers wanted to know the H


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Energy & Fuels practical AOP that started causing formation damage but struggled with the variation in measurements. 5.2. Interactive Evaluation Using Both Aspects of Laboratory and Field Data. Case study 3 required interactive discussion between the laboratory and field rather than a simple one-way feedback from laboratory to field. Because of the variation shown in Table 3, a discussion of laboratory aspects alone could not decide the appropriate and unique AOP. The change of flowing bottomhole pressure (FBHP) with time was reviewed, as shown in Figure 14. At the start of production,

Figure 15. Optimum flowing bottomhole pressure control to mitigate the asphaltene problem.

6. DISCUSSION Phase behavior of asphaltene should be recognized as a sequential process of particle growth, except for a portion of reversible process in which small asphaltene particles just precipitated under APE-inside conditions can be redissolved by leaving these APE conditions. In this sequential process, asphaltene is precipitated, followed by its deposition; thereafter, actual problems start to be observed at an operating site. This means that precipitation is not equivalent to deposition but is an essential phenomenon that triggers deposition. A transition therefore exists between precipitation and deposition risks. Considering only precipitation risks to extraction without exceeding the threshold to deposition could lead to countermeasures that would be sometimes too conservative and result in opportunity loss. Certainly, precipitation risk within deposition risk should be managed by appropriate countermeasures: the difficulty is the uncertainty of the threshold in asphaltene flow assurance. Boschee has pointed out that improper management of subsurface uncertainty is often a reason for project difficulties, including cost overruns.63 Two case studies related to gas injection projects evaluate the precipitation risk of asphaltene in the case of adding injection gases. Both evaluations revealed that some operational conditions were subject to precipitation risks. If extremely radical management of those risks was undertaken, there was a possibility of canceling the projects as a result of too pessimistic decision; however, a multi-disciplined discussion could handle those risks by avoiding opportunity/asset profitability loss. In case study 1, the facility engineering discipline could proceed with the gas injection project by monitoring asphaltene risks at the surface facilities. By investment in an injection pump or an asphaltene inhibitor/dispersant in preparation for potential risks from the beginning of the project, then if no asphaltene issue actualizes, the investment will be wasted; however, if asphaltene problems are encountered without any preparation, the project merit would deteriorate by taking a long time to install such a chemical injection pump from scratch, leading to production opportunity loss. The minimal recommendation to prepare an installation place could be an optimum compromise to satisfy both risk management and cost saving. In case study 2, the reservoir simulation engineering discipline were able to provide history-matched flow simulation results. By comparison of timings of observations of asphaltene deposits and gas breakthrough at the asphaltene observed wells, the risks could be correctly recognized and predictable. In this

Figure 14. AOP estimated from flowing buttonhole pressure history in well G.

FBHP showed a pseudo-steady state. Subsequently, an inflection point was observed at 3700 psia after a certain amount of oil production and depletion of the reservoir pressure. It was, however, also difficult to judge the practical AOP on the sole basis of field observations, even though asphaltene plugging might be one possible reason influencing the FBHP. Further details regarding productivity changes relative to the AOP are discussed by Uetani.62 The value of this inflection point was compared to experimentally measured results. It matched the AOP range (3300−4000 psig) measured by HPM. This agreement between the inflection point and the HPM-based data gave confidence in estimating the practical AOP. An inflection point of 3700 psia was consequently considered to be the practical AOP, namely, the starting point of formation damage. This practical HPMbased AOP became very useful in optimizing the reservoir pressure control. Discussion points are summarized in Figure 15. Without any pressure control, asphaltene-removal jobs were frequently required to restore reservoir productivity. Such frequent shutdown and removal jobs increased operating costs. Using AOP values determined by LST as the minimum operating pressure, i.e., too conservative pressure control, the asphaltene-removal jobs could be avoided but production opportunity would be lost. Here, using the realistic FBHPbased AOP for baseline control, advantages could be achieved from both maximizing production potential and mitigating asphaltene-removal jobs. The green hatched area shown in Figure 15 represents additional production potential compared to the case using the LST-based AOP. Using this case study, a workflow procedure for pressure control optimization was suggested, as shown in Figure 16. I


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Figure 16. Workflow of interactive discussion between the laboratory and site for optimizing pressure control in the asphaltene-suffered field.

bottomhole flowing conditions at production wells in the GIP area. The findings were compatible with observations of two wells: one had asphaltene deposits around the gas breakthrough that accumulated enriched gas, and the other was free of asphaltene deposits after gas breakthrough that accumulated lean gas. The findings contributed operationally to optimizing timings of remedial actions when enriched gas was close to the production wells. The third case demonstrated how to evaluate realistic AOP values interactively using both laboratory and field observations. To optimize pressure control not only to maximize production potential but also to avoid asphaltene-removal jobs, it was necessary to determine the AOP at which formation damage started. Consequent to the comparison between the AOP values measured using different techniques and the FBHP trend, the inflection point of FBHP within the HPM-based AOP range was judged as an actual point at which the formation damage occurred.

case, gas−oil ratio (GOR) data acquisition to provide warning signs of gas breakthrough may be useful for predicting the maximum asphaltene risks. Case study 3 was a more straightforward approach to detect the AOP threshold at which formation damage actually starts. For this purpose, the surveillance discipline cooperated in the evaluation of various AOPs. Periodic FBHP surveys could contribute to finding signs of formation damage. This work has demonstrated that practical and appropriate feedback from laboratory to field requires multi-disciplined discussions to enable projects to move forward. Risks inherent in one discipline can be manageable on the basis of discussions in that discipline; however, options of countermeasures recommended from an independent discipline might be limited. A greater choice of remedies could be derived from “fresh eyes” of other disciplines. Recent risk management trends in project delivery decisions are more nuanced: an appropriate level of flexibility is considered useful as a strategy for coping with uncertainties.

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7. CONCLUSION Three case studies have demonstrated how laboratory and modeling studies contributed practically to addressing asphaltene issues in the field. The first case involved preparatory work for a future gas injection project. The asphaltene precipitation risk was assessed by numerical modeling sensitivity studies assuming various types of injection gases and mixing ratios. By comparison of surface facility operating conditions and APEs, some risks were identified when gas was injected. The study eventually recommended a modification to the wellhead platform design that involved ensuring enough space in the layout for remedial action, such as installing an inhibitor injection pump. A preinvestigation was also recommended to check the feasibility and capability of the electrical supply for the pump. The second case involved identification of a protocol for adequate remediation of asphaltene in a gas injection pilot. Static investigation of APE estimated low asphaltene precipitation, even though actual asphaltene deposits were observed at the well. To solve this anomaly, a dynamic investigation of APE was carried out, taking the VGD process into account. This showed that the APE area shifted, covering the

AUTHOR INFORMATION

Corresponding Author

*E-mail: [email protected]. Notes

The authors declare no competing financial interest.

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ACKNOWLEDGMENTS The authors thank ZADCO, ADMA-OPCO, ADNOC, and TOHO EARTHTECH, Inc. for permission to publish this paper. The authors also acknowledge the co-operation of members of the SUFD team in ZADCO and the LZFD team in ADMA-OPCO in compilation of data. The authors also thank the KBC-Infochem team for assistance in improving the module.

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REFERENCES

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Contribution from Laboratory to Field: Case Studies of Asphaltene

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