Hazarika, Simanta (Oil & Natural Gas Corporation Ltd) | Rathod, P. Ramulu (Oil & Natural Gas Corporation Ltd) | Burla, Ravishankar (Oil & Natural Gas Corporation Ltd) | Das, Gour Chandra (Oil & Natural Gas Corporation Ltd) | Rao, Bkvrl (Oil & Natural Gas Corporation Ltd) | Deuri, Budhin (Oil & Natural Gas Corporation Ltd)
Subsea flow lines in deep water are typically exposed to high pressure and low temperature conditions which can create problems due to formation of gas hydrate. The gas hydrate formed can plug the flow lines causing not only loss of production, but may also create severe safety and environmental hazard. Moreover, dissociation of these plugs may take weeks or even months. Assessment of the hydrate formation potential during both steady is therefore an essential part of field development studies.
The paper presents a case study of a gas field located in KG basin of India which was brought on production in 2018. The objective of the study was to assist the on-site team on issues related to hydrate inhibition during ongoing initial start-up operation and assess the arrival time of rich MEG in the onshore plant in view of turn down flow conditions during commissioning.
The study also demonstrates how the transient simulations helped to monitor progress, identify and respond quickly to address the challenges during initial start-up operation of the deepwater gas field in Indian east coast. It emphasizes the need for accurate estimation of rich MEG arrival time and the minimum required gas flow rate from the subsea wells to ensure timely return of rich MEG to the onshore plant in order to avoid disruption in hydrate inhibition in the subsea system.
Sengupta, Partha (Oil and Natural Gas Corporation Limited) | Katre, Narendra (Oil and Natural Gas Corporation Limited) | Suman, Abhinav (Oil and Natural Gas Corporation Limited) | Das, Barnali (Oil and Natural Gas Corporation Limited) | Pawar, Anil (Oil and Natural Gas Corporation Limited) | Deshpande, Sunil (Oil and Natural Gas Corporation Limited)
In any onshore gas installation, bath-heaters and high pressure separators are provided as standard surface facilities to take production from high pressure wells having hydrate forming tendency. Medium pressure separators are also provided to take production from medium pressure gas wells. The paper deliberates on an optimized surface installation for handling high pressure well fluids with possibilities of hydrate formation. The study has been carried out through steady state multiphase simulation considering pressure & production profile of the wells, consumer requirement and flow assurance i.e. hydrate formation. An optimized process scheme and production strategy is presented for early production from both high pressure and medium pressure gas wells in a single separator and without any bath heater.
Based on well test data, well completion data and pressure profile, simulation studies are carried out in steady-state multiphase flow simulation software to look into possibility of hydrate formation in the flow lines or in process piping. Flow from wells having high well-head pressures in the range of 120 to 165 kg/cm2g (ksc) are simulated by varying the separator pressure, flow line size & length and choke arrangement. Flow simulations are carried out for different choke combinations and flow line arrangements to keep well fluid temperature above hydrate formation temperature in the entire flow path from well head to separators.
It was established from simulations that flow from the well having highest production as well as highest well head pressure of 165 ksc can be taken by operating the separator at 33 ksc and adopting a multi-choke arrangement along the flow line without any possibility of hydrate formation in the system. The multi-choke arrangement consists of putting chokes including well head choke at well site, at installation inlet and the final choke at installation inlet manifold. The arrangement also envisages additional small length of flow line as buried portion near installation inlet to take advantage of heat gain from soil. From 2nd year onwards of the profile period, it is observed that with reduction in well head pressure to 132 ksc as per profile, the well can be produced by operating the separator at lower pressure without any hydrate formation. For rest of the wells, only multi-choke arrangement is found to be sufficient to prevent hydrate problem while operating the separator at even lower pressure throughout the profile period. It is also observed that higher production can be taken from the wells from 2nd year onwards on account of operating the separator at lower pressure.
The optimized scheme has marked deviation from the earlier proposed standard scheme with substantial reduction in number of equipment and consequent reduction in CAPEX & OPEX. This novel process scheme and production strategy eliminate the need for investment in both high pressure separator and hydrate mitigation measures like heat tracing, methanol injection or bath-heaters. This innovative production strategy also facilitates better recovery from the gas wells on account of operating the separator at lower pressure.
Mancilla-Polanco, Adel (University of Calgary) | Johnston, Kim (University of Calgary) | Richardson, William D. L. (University of Calgary) | Schoeggl, Florian F. (University of Calgary) | Zhang, Y. George (University of Calgary) | Yarranton, Harvey W. (University of Calgary) | Taylor, Shawn D. (Schlumberger-Doll Research)
The phase behavior of heavy-oil/propane mixtures was mapped from temperatures ranging from 20 to 180°C and pressures up to 10 MPa. Both vapor/liquid (VL1) and liquid/liquid (L1L2) regions were observed. Saturation pressures (VL1 boundary) were measured in a Jefri 100-cm3 pressure/volume/temperature (PVT) -cell and blind-cell apparatus. The propane content at which a light propane-rich phase and a heavy bitumen-rich (or pitch) phase formed (L1/L1L2 boundary) was visually determined with a high-pressure microscope (HPM) while titrating propane into the bitumen. High-pressure and high-temperature yield data were measured using a blind-cell apparatus. Here, yield is defined as the mass of the indicated component(s) in the pitch phase divided by the mass of bitumen in the feed. A procedure was developed and used to measure propane-rich-phase and pitch-phase compositions in a PVT cell.
Pressure/temperature and pressure/composition phase diagrams were constructed from the saturation-pressure and pitch-phase-onset data. High-pressure micrographs demonstrated that, at lower temperatures and propane contents, the pitch phase appeared as glassy particles, whereas at higher propane contents and temperatures, it appeared as a liquid phase. Ternary diagrams were also constructed to present phase-composition data. The ability of a volume-translated Peng-Robinson cubic equation of state (CEOS) (Peng and Robinson 1976) to match the experimental measurements was explored. Two sets of binary-interaction parameters were tested: temperature-dependent binary-interaction parameters (SvdW) and composition-dependent binary-interaction parameters (CDvdW). Models derived from both types of binary-interaction parameters matched the saturation pressures and the L1L2 boundaries at one pressure but could not match the pressure dependency of the L1L2 boundary or the measured L1L2 phase compositions. The SvdW model could not match the yield data, whereas the CDvdW model matched yields at temperatures up to 90°C.
Jarrahian, Khosro (Heriot-Watt University) | Sorbie, Kenneth (Heriot-Watt University) | Singleton, Michael (Heriot-Watt University) | Boak, Lorraine (Heriot-Watt University) | Graham, Alexander (Heriot-Watt University)
Scale inhibitor (SI) squeeze treatments in carbonate reservoirs are often affected by the chemical reactivity between the SI and the carbonate mineral substrate. This chemical interaction may lead to a controlled precipitation of the SI through the formation of a sparingly soluble Ca/SI complex which can lead to an extended squeeze lifetime. However, the same interaction may in some cases lead to uncontrolled SI precipitation causing near-well formation damage in the treated zone. This paper presents a detailed study of the various retention mechanisms of SI in carbonate formations, considering system variables such as the (carbonate) formation mineralogy, the type of SI and the system conditions. Apparent adsorption (Γapp) experiments, described previously (
For all SIs, both adsorption (Γ) and precipitation (�?) retention mechanisms were observed, with the dominant mechanism depending on SI chemistry, temperature and mineralogy. Differences were observed between the "apparent adsorption" (Γapp) levels of polymeric, phosphonate and phosphate ester scale inhibitors, as follows: For the polymeric SIs (PPCA, PFC and VS-Co), the highest retention levels were observed at low pH for all carbonate substrates, due to the increase in divalent cations (Ca2+ and Mg2+) available from rock dissolution for SI-M2+ precipitation. For phosphonate (DETPMP) and phosphate ester (PAPE) SIs, the retention level was greatest at higher pH values, as the SI functional groups were more dissociated and hence available for complexation with M2+ ions. The polymeric VS-Co showed the lowest amount of precipitation (Γapp ~ 1.2 mg/g) in contact with dolomite substrate due to the presence of sulphonate groups (low pKa); indeed this showed low Γapp which was predominantly pure adsorption. However, a small amount of precipitate was observed by ESEM/EDX and PSA. For polymeric inhibitors, the retention level (Γapp) was highest on calcite (highest relative calcium content), followed by limestone and then dolomite. Phosphonate and phosphate ester SIs showed the highest retention levels on dolomite (higher final solution pH and more SI dissociated), followed by limestone and calcite. For all SI species, higher retention (more precipitation, �?) was observed at elevated temperature. At lower temperatures, a more extended region of pure adsorption was observed for all SIs.
For the polymeric SIs (PPCA, PFC and VS-Co), the highest retention levels were observed at low pH for all carbonate substrates, due to the increase in divalent cations (Ca2+ and Mg2+) available from rock dissolution for SI-M2+ precipitation. For phosphonate (DETPMP) and phosphate ester (PAPE) SIs, the retention level was greatest at higher pH values, as the SI functional groups were more dissociated and hence available for complexation with M2+ ions.
The polymeric VS-Co showed the lowest amount of precipitation (Γapp ~ 1.2 mg/g) in contact with dolomite substrate due to the presence of sulphonate groups (low pKa); indeed this showed low Γapp which was predominantly pure adsorption. However, a small amount of precipitate was observed by ESEM/EDX and PSA.
For polymeric inhibitors, the retention level (Γapp) was highest on calcite (highest relative calcium content), followed by limestone and then dolomite. Phosphonate and phosphate ester SIs showed the highest retention levels on dolomite (higher final solution pH and more SI dissociated), followed by limestone and calcite.
For all SI species, higher retention (more precipitation, �?) was observed at elevated temperature. At lower temperatures, a more extended region of pure adsorption was observed for all SIs.
The information presented in this study will help us in SI product selection for application of squeeze treatments with longer squeeze lifetimes in carbonate reservoir based on mineralogy and reservoir conditions. In addition, this study provides valuable data for validating models of the SI/Carbonate/Ca/Mg system which can be incorporated in squeeze design simulations.
Abdelgawad, Khaled (King Fahd University of Petroleum & Minerals) | Mahmoud, Mohamed (King Fahd University of Petroleum & Minerals) | Elkatatny, Salaheldin (King Fahd University of Petroleum & Minerals) | Patil, Shirish (King Fahd University of Petroleum & Minerals)
Barium Sulfate (Barite) is one of the common oil and gas field scales formed inside the production equipment and in the reservoir. Barite is also a common weighting material used during drilling oil and gas wells. Barium sulfate scale may exist as well in carbonate formations. The removal of barium sulfate from calcium carbonate formation is a challenging problem because of the solubility of calcium carbonate is higher compared to that of barium sulfate in different acids. In addition, barium sulfate is not soluble in the regular acids such as hydrochloric (HCl) acid and other organic acids.
In this paper, the effect of calcium carbonate on barium sulfate solubility in a chelating agent and converter catalyst was investigated using solubility experiments at 80°C as a function of time. 20 wt.% DTPA with 6 wt.% potassium carbonate (converter) were used at pH of 12. The effect of calcium chelation on the barium sulfate solubility was studied in two scenarios. The first scenario when Barium sulfate is dissolved first then the solution reacts with calcium carbonate. The second scenario when both calcium carbonate and barium sulfate are exposed to the DTPA solution at the same time. In addition, the effect of calcium carbonate loading on the barium sulfate solubility was determined using 25, 50, 75, and 100 wt.% of the scale as calcium carbonate. As an evaluation criterion, inductively coupled plasma (ICP) was used to analyze the cation concentration and determine the solubility of each scale type.
For the two scenarios of barium sulfate dissolution, the presence of calcium carbonate had a significant effect on the solubility of barium sulfate. When DTPA solution got saturated first with barium cations after 24 hours, and the addition of calcium carbonate to the solution will cause immediate barium drop of solution (concentration drop from 2140 to 1984 ppm in 30 min in 50 ml solution) which cause precipitation of barium sulfate. In addition, simultaneous chelation of both calcium carbonate and barium sulfate showed a low barium sulfate solubility compared to calcium carbonate. This can be explained by the high affinity of DTPA to calcium compared to barium.
It is highly recommended to account for the presence of any calcium source during the design of the chemical formulation for barium sulfate scale removal using DTPA. Therefore, DTPA treatment formulation is recommended in sandstone formations. Field results can be completely different from laboratory results if Ca2+ chelation from carbonate rocks is ignored.
Geochemical scale formation and deposition in reservoir is a common problem in upstream oil and gas industry, which results in equipment corrosion, wellbore plugging, and production decline. In unconventional reservoirs, the negative effect of scale formation becomes more pronounced as it can severely damage the conductivity of hydraulic fractures. Hence, it is necessary to predict the effect of scale deposition on fracture conductivity and production performance.
In this work, an integrated reactive-transport simulator is utilized to model geochemical reactions along with transport equations in conventional and unconventional reservoirs considering the damage to the fracture and formation matrix. Hence, a compositional reservoir simulator (UTCOMP), which is integrated with IPhreeqc, is utilized to predict geochemical scale formation in formation matrix and hydraulic fractures. IPhreeqc offers extensive capabilities for modeling geochemical reactions including local thermodynamic equilibrium and kinetics. Based on the amount of scale formation, porosity, permeability, and fracture aperture are modified to determine the production loss. The results suggested that interaction of the formation water/brine and injection water/hydraulic fracturing fluid is the primary cause for scale formation. The physicochemical properties such as pressure, temperature, and
During hydraulic fracturing, precipitation of barite and dissolution of calcite are identified to be the main reactions, which occur as a result of interaction between the formation brine, formation mineral composition, and injection water/hydraulic fracturing fluid. Calcite dissolution can increase the matrix porosity and permeability while barite precipitation has an opposite effect. Therefore, the overall effect and final results depend on several parameters such as HFF composition, HFF injection rate, and formation mineral/brine. Based on the fracturing fluid composition and its invasion depth in this study, the effect of barite precipitation was dominant with negative impact on cumulative gas production. The outcome of this study is a comprehensive tool for prediction of scale deposition in the reservoir which can help operators to select optimum fracturing fluid and operating conditions.
Asphaltene deposition and plugging of pipelines during oil production and transportation is considered a challenging flow assurance issue. Instead of adding dispersants, the concept proposes to remove asphaltenes from the flow stream by means of electro–deposition prior to transportation to prevent later deposition. This study mainly examined the effect of molecular composition on the efficiency of electro-deposition. Two sources of asphaltene, namely asphaltenes from coal tar ("AS-C") and asphaltenes from bitumen ("AS-B") with different molecular composition were collected in this study. Elemental analysis revealed that both AS-B and AS-C possessed transition metals (V and Ni) and heteroatoms (O, N and S). The effect of oil components on the stability of two asphaltenes was studied. After conducting the electro–deposition of both asphaltenes with various oil components and electric field strength, the deposition charge and recover rate was recorded and compared. During stability test, the amount of precipitated AS-B decreased with increasing aromaticity of solvent, while that of AS-C was constant. For electro–deposition, the electro–kinetic behavior of AS-C reveals strong sensitivity to the oil components. Interestingly, both asphaltenes exhibited a change in the net charge, which occurred under 6000 V/cm and 12000 V/cm for AS-B and AS-C respectively, as evidenced by a change in the electrode upon which deposition ocurred. Based on the results, the efficiency of electro–deposition is confirmed to depend upon the metal and heteroatoms of asphaltenes; in addition, and by interaction with these elements, the oil composition and electric field affected the stability, net charge, and electro–kinetic behavior of apshaltene. However, our study is the first to show that the current density plays a role in the net charge of the asphaltene molecule and offers an explanation to the controversy over the polarity or the charge sign of asphaltenes, which gives a clue to understanding the microstructure of asphaltenes. In addition, this is the first study to include the effect of oil components and electric field strength on the performance of deposition, which makes further optimization of the proposed process possible.
Wang, Xin (Rice University) | Ko, Saebom (Rice University) | Liu, Ya (Rice University) | Lu, AlexYi-Tsung (Rice University) | Zhao, Yue (Rice University) | Harouaka, Khadouja (Rice University) | Deng, Guannan (Rice University) | Paudyal, Samridhdi (Rice University) | Dai, Chong (Rice University) | Kan, Amy T. (Rice University) | Tomson, Mason B. (Rice University)
Iron sulfide scaling is a severe problem in flow assurance and asset integrity in oil and gas and deep-water production. FeS scale control is challenging due to the extremely low solubility, fast precipitation kinetics and complexity of ferrous iron and sulfide chemistry. Despite the ubiquity of FeS, we have limited understanding about the kinetics and thermodynamics of iron sulfide. To address this problem, we have developed a reliable anoxic plug flow reactor using argon gas to remove oxygen and PIPEs or MES buffer to control pH. The FeS (mackinawite) solubility, precipitation kinetics and phase transformation were the focus of this study. The impact of temperature (25 – 90°C), pH (5.92 – 6.91), ionic strength (0.15 – 4.30 M), Fe(II) to S(-II) ratio, dispersant and chelating reagent have been investigated. It was found that mackinawite is always the first FeS precipitated and could be stable for a week. It was suggested that low pH, high temperature and low ionic strength could accelerate the FeS phase transformation. FeS precipitation is under diffusion control at pH lower than 6.1, which could be accelerated by high temperature and high ionic strength. But the precipitation kinetics would be faster at higher pH. Some evidence suggests the importance of neutral FeS(aq) species at pH 6 −7. A polymeric compound containing amide functional group showed a promising effect by controlling the FeS particle size and reducing FeS scale retention rate. EDTA showed satisfactory FeS scale inhibition effect, as well as reducing FeS scale retention and H2S corrosion rate.
Produced water composition analysis provides evidence of what geochemical reactions are taking place in the reservoir. This information can be useful for predicting and managing oilfield mineral scale resulting from brine supersaturation.
This paper presents results of a study of the produced brine compositions from three wells in a field operated in the North Sea, with geochemical modelling complementing the analysis. The findings presented in this work provide evidence of magnesium depletion and sulphate retardation in a sandstone reservoir at 130° C.
This adjusted formation water composition was then used for calculations of the injection water fraction in each of the produced water samples. The Reacting Ions Toolkit was used to plot data in a variety of formats, including ion concentration vs. ion concentration, ion concentration vs. injection water fraction and ion concentration vs. time to identify trends and to examine the extent of involvement of the various ions in geochemical reactions.
The breakthrough of sulphate, a component primarily introduced during seawater flooding, was retarded during injection water breakthrough. Observed sulphate concentrations were lower than predicted for the case of brine/brine interactions only. The implication of this sulphate reduction was lower minimum inhibitor concentration required to control scale formation and longer squeeze treatment lifetimes for the operator.
A brine/rock interaction mechanism was proposed that involves magnesium depletion and is reproduced in the reactive transport model. 1D reactive transport modelling was performed to match possible
As the oil and gas industry continues to operate in more complex and deeper water environments downhole scale control via scale squeeze treatments becomes an ever-increasing technical challenge. It is therefore essential that effective scale management strategies are adopted which incorporate suitable scale inhibitor (SI) selection, analysis and treatment design procedures to provide optimal and cost-effective squeeze treatment lifetimes to maximise oil production and reduce well intervention costs.
In this paper key factors are evaluated in order to provide a guidance to selecting a suitable treatment strategy for downhole scale control in co-mingled sub-sea well and the impact of chemical retention, minimum inhibitor concentration (MIC), limit of quantifiable detection (LOQD) and well dilution factors on treatment design and strategy are discussed. The pros and cons of different treatment strategies are presented in this paper and consideration is given to following three treatment strategies: Treating all wells with the same chemical and over designing the chemical treatment lifetime ie 18 months and then re-treating all wells after 12 months; Treating individual wells with tagged versions of the same scale inhibitor chemical; Treating individual wells with different scale inhibitors.
Treating all wells with the same chemical and over designing the chemical treatment lifetime ie 18 months and then re-treating all wells after 12 months;
Treating individual wells with tagged versions of the same scale inhibitor chemical;
Treating individual wells with different scale inhibitors.
Options (ii) and (iii) offer the ability to design similar treatment lifetimes for each well but have the flexibility to monitor wells individually and re-squeeze when required.
Examples are provided for treatment options (ii) and (iii) based upon a field example to illustrate the design concepts for fluorescent (F) and phosphorus (P) tagged polymers in two co-mingled wells and a theoretical example for treating three co-mingled wells with different scale inhibitors, one of which could be a phosphonate with two tagged polymers.
This paper presents an overview of the key factors that influence chemical selection and treatment design for co-mingled wells in the same flow line. In addition, it will highlight important concepts to provide guidance for the design of effective treatment strategies for squeezing co-mingled wells in sub-sea and deepwater environments.